Helmerich and Payne Inc (HP) 2013 Q3 法說會逐字稿

Good day and welcome to the third fiscal quarter earnings conference call. All lines are currently in a listen-only mode. Later, you will have the opportunity to ask questions during the question-and-answer session. And please note, today's call is being recorded. It is now my pleasure to turn the conference over to Juan Pablo Tardio, Vice President and CFO of Helmerich & Payne.

Thank you and welcome, everyone. With us today are Hans Helmerich, Chairman and CEO, and John Lindsay, 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 over to Hans Helmerich.

Thanks, Juan Pablo. When you consider the challenging nature of the US land rig count so far this year, we're pleased with today's results, related to the performance of our drilling operations. Our overall field execution, measured in terms of efficiency gains, safety, cost containment and margin resiliency, all continue to deliver strong showing. You'll hear from John Lindsay about a more detailed account of these results, but first, let me mention a couple of highlights during the quarter.

First, the Board approved a large dividend increase, bringing our annual payment to shareholders to $2 per share. The action not only makes good on the promise that we're willing to return excess cash to shareowners, but also reflects a confidence, looking forward in our ability to pursue and all of the above strategy. Meaning, our strong financial and strategic position provides a combination of growth opportunities, and at the same time, allows us to provide a meaningful dividend payout and the ability to consider additional share repurchases.

Also, most of you saw where we sold one half of our Atwood position at a substantial gain during the quarter. While we have no current plans for additional sales at this time, we have been clear about our intention, over a reasonable time, to further rationalize our remaining equity holdings at Atwood and Schlumberger. If you had told us back in January that by the time of our July earnings call, oil prices would be well over $100, and that natural gas fundamentals and prices would be much improved, and that the East Coast would be enjoying a nice warm summer, all of that would've put a bounce in our step. So while we would have expected by now to have seen more traction towards improved activity levels, we're not discouraged about the longer-term. We think improvement is coming, but it's shifted slightly to the right.

It seems reasonable that things have developed more slowly for several reasons. The macroeconomic uncertainty has cast a downward bias over oil prices for a considerable period of time, leading to an extra measure of caution in capital spend discipline. The industry also seems to be catching its breath from a huge land rush and the associated activity around drilling oil leases and better understand new areas, as part of a massive shift into oil- and liquid-rich plays. At the same time, impressive efficiency gains have been realized, effectively acting as a certain buffer or cushion that has allowed operators to do more with less and has provided more bang for their buck.

Helping to capture these efficiency gains for customers has been central to our value proposition for over a decade. As drilling continues to become more complex and horizontal in nature, our differentiated performance will appeal to a growing customer base. Even in this market, we're pleased with our steady progress, our ability to capture increase market share, our improving field performance and our leading position to be able to quickly respond to opportunities and to take advantage of what we still believe to be an improving market landscape in the months ahead. Now, I'm going to return the call back to Juan Pablo.

Thank you, Hans. Strong results from drilling operations for the third fiscal quarter were primarily attributable to even better than expected performance in both the US land and international land segments. In addition, the Company realized almost $93 million in after-tax gains from sales of investment securities announced in May. And over $15 million in income from discontinued operations, elevating quarterly net income to $266 million, the highest in the Company's history. Our capital expenditures estimate for fiscal 2013 remains at approximately $890 million, and total depreciation for the year is expected to be between $450 million and $460 million. Our general and administrative expense for the year is expected to be between $125 million and $130 million, and our interest expense estimate, which is net of capitalized interest, is expected to be close to $6 million during fiscal 2013.

Our cash and cash equivalents balance, as of June 30, 2013, was approximately $480 million. Our current liabilities, as of that same date however, included approximately $180 million to be paid during this fourth fiscal quarter, related to our recently increased regular dividend, some debt that is due this year and income taxes corresponding to the recent sales of investment securities. Our effective income tax rate for continuing operations for the first nine months of the fiscal year and for the third fiscal quarter were 35.4% and 35.7%, respectively. We expect the effective rate for the fourth fiscal quarter to be slightly under 35%. Our remaining investment portfolio recently had a total pre-tax market value of approximately $309 million and an after-tax value of slightly under $200 million. I will now turn the call over to John Lindsay, and after John's comments, we will open the call for questions.

Thank you, Juan Pablo, and good morning, everyone. As you know, unconventional plays and horizontal drilling in the US land market have changed the competitive landscape and raised the barriers of entry to the business by a shift to drilling more complex horizontal and directional wells. Since our quarterly conference one year ago, we had--we delivered 30 new build AC-Drive FlexRigs to the US land market, and increased our market share from 13% to 15%. During that same time period, mechanical and SCR rigs combined have lost approximately 11% market share, and AC-Drive rigs have acquired that market share in the US land sector. We view this as a clear indication the replacement cycle of old, conventional rigs is ongoing. Mechanical and SCR rigs are going to the sideline, and are being replaced by new technology, AC-Drive rigs, and H&P FlexRigs continue to lead this replacement cycle.

We had another strong quarter led by our US land segment, where our US Land operating income increased 4.6% quarter-over-quarter to $236 million, and revenue days increased approximately 3% to 22,510 days, representing approximately 247 average active rigs in the third fiscal quarter, as compared to 243 active rigs in the prior quarter. We experienced a mix of term and spot market rigs for the quarter that averaged 160 rigs and 87 rigs, respectively. Average rig revenue per day decreased by $95 sequentially to $28,160 a day, and was largely unaffected by early termination revenue in the quarter, as compared to approximately $70 per day contribution by early term revenue in the second quarter.

Average rig revenue per day for rigs working on term contracts during the third fiscal quarter was approximately 12% higher than average rig revenue per day for rigs working in the spot market. About half of this difference is attributable to softening day rates in the spot market during the last year, as compared to day rates corresponding to term contracts, which were in average, settled in a stronger market. The rest is attributable to other factors, including a different mix in the type of rigs, regions and additional services corresponding to the group of rigs on the spot market, as compared to those under term contracts. We were pleased with the third quarter results, where average rig expense per day decreased by $339 per day sequentially to $12,746 per day.

You've heard us talk about our organizational focus on cost management, as part of a larger effort to leverage off of our growing fleet. Our field operations and back office support have done an excellent--exceptional job improving our daily operational expenses since the second quarter of 2012. We believe that consistency and operational expenses are a combination of many initiatives, including our new procurement system, improved processes and the operation of a standardized fleet of AC-Drive rigs designed and built by H&P. And as a result, average margin per day increased by $244 to $15,414 per day for the third fiscal quarter. That is 64% and 75% greater than our two largest competitors.

In addition, during the third quarter, the US land segment took delivery of three new build FlexRigs with term contract commitments. We plan to continue a build cadence of two FlexRigs per month for the rest of the calendar year. We continue to have encouraging conversations with customers, regarding new builds with multi-year term contract commitments. With our fleet size and continuity, we have the flexibilities to build required capital spares and convert those into new FlexRigs, as needed in the future. Today, our rig--our active rig count stands at 243 FlexRigs, as compared to 246 rigs on June 30th.

Even with the choppy rig activity we are experiencing, we remain confident in the fourth fiscal quarter operational performance, where we expect revenue days to be flat to down 1%, compared to the third quarter. We continue to have strong term contract coverage, with 156 FlexRigs under term contracts and 87 operating in the spot market. With 243 active rigs, we have 55 available idle rigs, including 22 AC-Drive FlexRigs. We have averaged slightly over 20 stack AC FlexRigs per quarter, beginning in the fourth fiscal quarter of 2012. Of the 22 stacked AC rigs we have today, over half of those rigs earned revenue during the last two quarters.

Even with the soft market conditions, we have experienced resiliency in spot market pricing, which is a reflection of the quality of our people, FlexRigs and the performance they are able to deliver to our customers. Assuming market conditions stay the same, without any improvements to the fourth quarter, we expect average FlexRig revenue per day, per rig day, to be down approximately $100 to $200 per day. With our recent cost performance, we believe our average rig expenses will be $12,900 per day, with a range of plus or minus 1% to 2%. We expect approximately $7.7 million in early terminations, and approximately $5.2 million in delivery delay revenues for the fourth quarter. Our term contract coverage for future quarters remain strong. We currently have an average of 154 FlexRigs under term contracts for the fourth fiscal quarter of 2013, and an average of 141 FlexRigs for the first fiscal quarter of 2014. And an average of 113 rigs for all of fiscal '14.

Excluding costs that are passed onto customers, we now expect average rig revenue per day for our rigs on term contracts to remain relatively flat for the remaining quarter of fiscal 2013 and to increase by approximately $100 per day in average during fiscal 2014. This is compared to the average rig revenue per day for rigs under term contract during the third fiscal quarter of 2013. Keep in mind that these references are only for rigs that are already under term contracts and exclude any future term contracts. In the theoretical event that spot prices and utilization remain relatively flat to the end of fiscal 2014, and excluding costs that would be passed on to customers, the total average revenue per day for the segment during fiscal 2014 would be expected to decline by approximately 2%, as compared to this year's third fiscal quarter.

Now, a few comments regarding the offshore segment results for the third fiscal quarter. Offshore operating income increased by approximately 3% to $14.1 million, as compared to the prior quarter. Revenue days increased by 1% to 728 days, as utilization remained constant at 89% for the segment. Average rig margin per day increased by $270 sequentially to $25,108 per day. Now, looking at the outlook for our offshore segment. As of today, we have eight rigs active and one rig stacked. We expect eight rigs to remain active throughout the fourth fiscal quarter. As compared to prior quarter, we expect offshore revenue days to be up approximately 1%, as we continue to operate eight rigs. We expect our offshore margins to be relatively flat, as compared to the previous quarters.

And now a review of the international land segment, where operating income decreased by approximately $4.7 million to $8.5 million. The primary factor driving the decrease was approximately $5.3 million of early termination revenue, recognized in the second fiscal quarter. Revenue days increased 5% to 2,132 days, as overall segment utilization improved from 78% to 80%. Average rig margin per day decreased $2,462 to $8,591 per day. Excluding early termination revenues of approximately $2,600 per day in the second fiscal quarter, margins improved slightly. The outlook for international activity should improve for the fourth fiscal quarter. Today, the international land segment has 26 of 29 rigs working, of which 15 are AC-Drive FlexRigs.

The active rigs by country include seven in Argentina, six in Columbia, six in Ecuador, three in Bahrain, and two each in the UAE and Tunisia. We currently have three idle rigs. Two are in Argentina and one in Colombia. As a result of this activity improvement, we expect international land revenue days to be up approximately 5% in the fourth quarter. Excluding the effect of early termination revenue, we expect international margins to be up approximately 10% to 15% sequentially, as costs associated with rigs transferring between locations subside and standard drilling operations commence. As a result of the exceptional performance of our FlexRigs in the Middle East and Latin America, we believe there is long-term growth potential for international land operation. However, even with the increased level of international interest, our bullish outlook is tempered by our experience that growth opportunities have tended to be more sluggish in international markets than we would have expected.

And in closing, we believe our FlexRig technology offering, organizational competency and focus to deliver safe, efficient and cost-effective operations for our customers position H&P for long-term growth. Through this competency and focus, we continue to deliver tangible results today and over the long term. Even in the face of a challenging rig market, like we have experienced in US land over the past year, during the third quarter, we delivered quarterly and year-over-year improvements in rig activity and daily cash margins. These achievements wouldn't have been possible without our people's commitment to the Company's vision of providing safe, efficient and cost-effective performance for our customers. That completes my operating segment remarks, and now I'll return the call back to Juan Pablo.

Thank you, John. We will now open the call for questions.

(Operator Instructions)

Jim Crandell, from Cowan.

Good morning, guys. My first question has to do with new builds, and it has to do both in the US and Canada. Could you address number one with new builds. It seems you had a very strong market share over the course of this cycle, and competitors are recognizing new builds here this year. And it seems on a very short-term basis, your market share has gone down. Do you think that that's due to competitors taking less of a day rate than you're taking, or is it just by chance, and you'll reestablish a leading market share as we go forward?

Thanks, Jim. First, we know very little about some of the points you bring up, in terms of what the day rates are, length of the term, construction costs, but if you think about the rig market today, it's been flattish at best. And it's also oversupplied, even in the AC Tier One segment, where you have 85 idle AC rigs industry-wide. The real oversupply, of course, is in the SCR and mechanical rig markets, and those have the challenge of not becoming more and more obsolete. So if a large part of your fleet is made up of that type of rig, and you've been losing market share, and you have new builds that are sitting on the ground, then you're a motivated seller, in terms of placing new builds.

Our situation is different than that, and we can afford to be more patient and we can let the market develop. We're not playing catch-up or having to rebuild our fleet. We have no mechanical rigs, as you know. We're not marketing any SCR rigs. And as our margins show, we're not discounting day rates today to buy up our activity. And our new builds cadence serves kind of two purposes. One, it gives us the optionality for capital spares, but it's--provides us an ability to respond quickly, where we can take those same spares and they become building blocks for new rigs.

So when you think about a rig's cycle, typically you absorb some of that overhang or some of that capacity. And then you begin to have customers interested and focusing on the type of rigs they want. And that's where we think we'll see some attractive new build opportunities. So we've said before, Jim, that our toughest competition for new builds is our own AC-Drive FlexRigs. And we would expect those today, those 22, we expect those rigs to be taken up in an improving environment. And then, that would lend itself to additional opportunities for new builds. So all this says that we should remain patient, and we're comfortable with both where our market share is and then also keeping with our manufacturing cadence.

Do you think, Hans, as operators look for rigs in the future for term capabilities, that there is a marked preference in the eyes of many of them for the FlexRig6 versus the Flex3? And that you'll see new builds because they really want the advanced capabilities of the FlexRig6?

I think you're talking about the Flex5.

Five. I'm sorry, I meant your next generation. (laughter)

No. That's okay. I'm glad you have that anticipation. Yes, I think that they're--we're seeing the market shift to more and more pad capable rigs. We lead in that space. And I think we're going to continue to see customers look for that. We've said--we talked about all of our pad capable rigs are AC-Drives. So, yes. Certainly, I think that is where the future goes, and we're confident that we're going to play leading role on that. Remember, we've got a 15% overall market share.

We've seen--and you mentioned it kind of in your question--we've seen our AC market share drop from just 40% to, I think, 38%. At one point, I suppose we had 100% of that market share. If we can bring our 15% up--everyone else is losing market share. We're gaining market share. If we can bring that 15% up, we can withstand and be patient, if we have a few basis points of the overall AC share slip. But, look. We're going to be a big player in the improving cycle and the ongoing demand for new builds.

And one last quick one, Hans. Do you--is--could Helmerich & Payne be a player for new builds up in the Horn River? There seems to be a lot of optimism about drilling for--in the advance of L&G requirements there. And certainly, they need the type of rigs that you make. Is that a market that you're looking at closely, in terms of entering?

Yes. I'll let John speak more to that, but there are a couple of markets that are developing. And may be early, but still, I think we'd be well-suited for.

Yes, Jim. I think from a rig quality and the type of rig and the application, there's a great match. You've heard us say before that we're going to move rigs on a demand-pull basis. We're not going to go in and try to buy up some markets. If we have customer sponsorship--and some of our larger customers would want to sponsor us somewhere in Canada or elsewhere--then yes, we have interest in that. So we'll just see how it plays out.

Okay. And you can be--John, you think you can be cost competitive in that market with new builds, with transporting them up to Horn River?

Well, I don't think that there's any question that from a cost of manufacturing and then mobilization--we mobilize rigs long distances. We have Canadian contractors that mobilize rigs, obviously to the US. But I think there are some tax implications that are beneficial for the Canadian contractors. I don't know that for sure, but I think that's right. So that's obviously a disadvantage. I wouldn't--I don't want to leave you with the impression that this is at top of mind, and this is--we're really aggressively pursuing that Canadian market. And as you know, there's very good Canadian contractors that have done a very good job with that market.

Okay. Good. Thank you very much.

Kurt Hallead, from RBC Capital Markets.

Thank you. Good morning. So I was hoping to get a little update on what the leading edge pricing dynamics are for the AC class rigs, both in terms of what the spot market dynamic is, and then what you think the pricing dynamic is for the long-term contract commitments that you've already discussed? And how--if you could give us an indication on how these pricing dynamics have changed over the course of the past quarter?

Kurt, this is John. In general, I think if you look at the last quarter and what we're talking about, going into the fourth quarter is our spot pricing. We've estimated it being down 2% to 3%, that shift of spot. When you say leading-edge, as you can imagine, we have different models of FlexRigs. And so, some are larger, some are smaller. So there's a range there. In general, I would kind of frame it in a mid-20s type of a rang--a ballpark.

Again, there's a lot of range there, depending on the operating area. Is it a winterized area? Is it non-winterized area? What's the size of the equipment? But overall for us, the trend has been--has softened a little bit, and it has since a year ago. But as we've said, I feel like we've held are own from that perspective, because of our performance. Did I answer your question, or is there more color you wanted there?

Yes. I wasn't quite sure on that leading edge in the mid-20s. Is that full-year contract dynamic, or were you still referring to spot pricing on that?

Well, that's spot pricing. Term contract pricing, obviously, is higher than that. As far as new build pricing, would be in the--again, dependant upon the operating area. So in some cases, it's going to be above mid-20s. In some cases, it's going to be below mid-20s.

Okay. And in light of the general lack of customer urgency for putting new rigs to work for the increased drilling efficiency, or however you want to put it, what's your sense on how your customers are looking at spending trends in the second half of the year? Do you get a sense that given the recent bump--and you indicated it in your press release--that with the recent bump in oil prices, are you already getting an indication, Hans, that EP companies are going to increase their spend in the second half of the year versus the first half of the year?

Well, I think what we're hearing is, the improvement in commodity prices have been often planned. And you know that they did a lot of their budgeting in the 80, 85 range, and stress test that down to 70 to 75. And I think that's the world they expected to see. And now we're in a world where we have prices in excess of $100. So I think what we're hearing anecdotally from folks is that, hey, that's going to help.

That's going to make a difference. That's going to drive cash flows, natural gas pricing is better than we had budgeted as well. And I think all of that moves, yes, Curt, into an emboldened outlook for the rest of this calendar year, and then certainly we'll get some momentum going. Assuming commodity prices hold, it's a momentum going into 2014. So I think that we're hearing a more upbeat sense from our customers in discussions.

Okay. That's great. Appreciate the color. That's all for me. Thanks.

Byron Pope, with Tudor Pickering Holt.

Good morning, guys. You recount in the Permian has continued to track higher, even though the overall rig count in the basin has been relatively flattish. So clearly, you're taking some market share there. So my question is, which FlexRig design seems to be resonating with customers in that region the most? And as you think about growing your rig counts over the next 12 months to 18 months in the Permian, does this have any notable implications for your overall fleet average day rates in margins? I'm assuming the answer is no, but I'd just like to hear your thoughts on that.

Yes, Byron. This is John. The--I think the--probably the rig of choice has probably been the FlexRig3. In some cases, there's a pad application. At most cases at this stage, there isn't, but there are some pad applications. We have the FlexRig4, that super single that we have, I think almost all of those in the US are working in the Permian.

And that's been a real popular rig design, as well. We've built a couple of those new in the last year. But I think the majority of the demand is going to be for FlexRigs3s, the 1,500 horsepower, fast rig moves to drill the horizontal wells. I think that's where we've gotten most of our growth. As far as the pricing, no, I don't expect at this stage that there would be an increase in pricing in that basin and it having an impact of improving the overall pricing going forward. Not with what we see right now.

Okay. And then just a second question from me. Juan Pablo, you mentioned that the fiscal 2013 CapEx budget is $890 million roughly. Is it early to say, given that we're approaching the end of your fiscal year, directionally how you guys are thinking about fiscal 2014? And thinking directionally, is it higher, flattish, lower, year-over-year?

Well, we will be talking more about that during our next conference call, where we're going to have related meetings to look at the prospects, et cetera. At this point, it's a little early to--for us to start talking about that. But--Byron, sorry.

Hey, Byron. This is John. I wanted to add. We do have--I just remembered. We have had some conversations as well on FlexRig5s in the Permian as well. Again, we are still a little bit early on as much of the pad drilling as we've seen, as an example, in the Eagle Ford or the Bakken. But I do think we'll have with FlexRig5s, as that market matures and goes to more pad drilling. I think we'll see that happen.

Okay. Thanks, guys. I appreciate it.

Dave Wilson, with Howard Weil.

Good morning, gentlemen. Thanks for taking my questions. First, just wondering on rig efficiencies and how much is left out there. Is it a matter of the industry more fully deployed the best rigs or more pad drilling, or is there something else? And do these efficiency gains mean we can expect kind of an acceleration of the older, more legacy rigs moving to the sidelines, sooner rather than later?

I will let John do some of that, but yes, I think the sense of your question is right. The bar just gets placed higher and higher, and as you have more horizontal drilling and more well complexity--John talked about even in the Permian. If you had told us that we'd have had the market share made up from Flex3s and now Flex5s in the Permian, it just speaks to, Dave, what your question is getting at. So I think the performance bar is higher and that really suits us well. I also think when you look at our performance, our efficiency capture, based on footage drilled, has gone up considerably last year over the previous year. Year-to-date, it's up. An impressive number, as well.

So we keep finding ways--John can give more detail on that--but we keep finding ways to improve our performance. And I think the customer and our brand reputation is for doing that, and so the collaboration and the partnership we have with customers continues to drive better performance. The other aspect that we uniquely bring, that I don't think our competitors with their different fleet type sizes, ages, predominance of older rig classes. We bring the uniformity and the all AC-Drive offering that allows us to push not only that cutting-edge efficiency, but overall field efficiency, overall customer roster performance, bringing the very best well in the field in closing that delta with the other average and less highly performing wells. So that's a very attractive capture from a customer standpoint, and we're uniquely positioned to continue to drive that as we're doing today. John, did you want to add some to that?

Well, I--Dave, when you consider the number of AC rigs working today, versus even a year ago. And you start considering several hundred mechanical and SCR rigs going to the sideline, increasing number of AC rigs. And of course, the rigs that go to the sideline that represent the mechanical and SCR rigs are going to be the bottom of the barrel, right? They're going to be lower end performers. So from a distant, overall industry and rig count perspective, it shouldn't be any surprise that efficiencies are improving.

And then, when you start looking at it on a comparative base--let's just use the Flex3 as an example--we continue to see--even with all of the improvements that we've seen over the last three years, we continue to see improvements in 2013. And as we have said before, Dave, it's not just the rig. It's a lot of other things associated with the rig, and working together as a team with your customer. But I still think there's significant performance improvements that can be made when you consider what--when you consider our best in class well or the technical limit, and you compare that to our average well in the field, there's still quite a bit of opportunity, I think, ahead for us.

Okay. Great. And then kind of sticking with the efficiency theme here on the cost front and how you guys have done the cost management, do you think this quarter is kind of indicative of the best it can get, as far as from a cost perspective? $12,700 per rig? Do you think you can get better than that, or is that--have we kind of reached the technical limit there, as well?

Well, we've--I think we've been a little lower in previous quarters, but the variables change, quarter to quarter. There's--again, we're--in some previous quarters, we hadn't stacked as many rigs, and then reactivated as many rigs. So there is a lot of moving parts that are taking place. The demands that our customers have, in terms of drilling these wells--when we talk about efficiency gains, yes, it's large part. It's because you've got a better technology rig.

But we're also running the equipment quite a bit harder than we did two or three years ago. And so obviously, when you're running equipment harder, equipment wears out more quickly. You go through more expendables, which drive costs up. And so that's--part of our message and part of what Hans was talking about earlier is our efficiency gains. We're also a working to--well, how do you maintain a better cost structure?

How do you maintain a better maintenance schedule, in order to drive your operational costs? At least keep them flat, and hopefully drive them down, even in the case where you're working the rigs significantly harder than you did a couple of years ago. So to answer your question, I think the [12-9], plus or minus 1% or 2%, based on what we know right now, I think makes a lot of sense. We have had some quarters in the past year or year and half, I think that we were slightly under the [12-7]. But I don't see us going back to those levels right now.

Okay.

Dave, the only thing I would add to that is I think it's a real accomplishment of our folks, and you've watched it with us for several quarters now. And it's the result of--it's more than just trying hard. It's good systems. It's managing costs. We see that as being a competitive advantage. When you look at the cost experience of some of our peers, and what John just said about--hey, this is a business where we're running that equipment hard and that's going to become more and more of a challenging mark to set. So I think we continue to have a lot of focus on it.

Okay. Great. Thanks, guys. I'll turn the call back over.

Robin Shoemaker, from Citigroup.

Thanks a lot. Hans, I wanted to ask you. On the new building program, you didn't announce new term contracts signed for new builds, I believe, this quarter. You did announce two back in April, and I think, three in January. So anyway, I think the right number is five, year-to-date. And you're building them at a pace of--faster pace, of course. And I assume we're coming up with this cadence you have now, of two per month, to a point where you're delivering some rigs that don't have term contracts. So kind of wondering whether you believe you should hold off to get a term contract for a new build FlexRig or offer that into the spot market?

Thanks, Robin. And thanks also for getting the count right. You were correct. Part of what happens, I suppose, if you have some misinformation out there. One of our peers this week talked about that we had only announced eight new builds under long-term contracts since the first of 2012, when in fact the number is much higher, at 17. Part of that depends on where you also capture the time bracket. Had they gone back a little further, the comparison would have been our 72 new build orders to their 25.

So we're talking about a snapshot in time. This quarter, we didn't have any announcements. I talked about--part of that is patience being a virtue, because--in fact, you watch this market closely. You know we're not at a stage where you would normally be in the cycle, at a point where you had a lot of new build announcements. And so what people are doing is they're using their new builds to stem the loss and to stop the bleeding of market share, and watching their activity go down.

So we can be more patient than that, and when I think of our two rig cadence, we're very new into a place where we haven't had all of these rigs under new--under long-term contracts. And we've talked with you before and others that we've run at zero spares for so long, because we could pull them out of our manufacturing queue, that were still in that phase where we're unitizing capital spares and we're having, in effect, the ability to either support a growing, larger fleet with those spares or turn those into, in essence, equipment kits that become fully commissioned rigs. So that's where we are today. We have that optionality.

As we go forward, we've talked about our line of sight would say, we're very comfortable with building two rigs per month, through the end of the year. And we can continue to watch that and monitor that, and look at that. We're doing that because we think the market's going to improve, and there's going to be a right time to put those rigs into a fully commissioned status and place them under long-term contract. And so, we'll bide our time. We'll be patient. What we hope, the market trends that way. We think it will, but I think we're in a good spot right now.

Yes. Okay. So on the 22 idle FlexRigs that you mentioned, clearly, there's a trade-off there. If you could put them all back to work at a lower price, you're defending a price level. So would that be--the strategy is to just say, okay, here's the level at clearly which we won't go, or where do you really want to get the majority of those idle rigs working?

Well, it's a fair observation, and you're right. You can see it in our operating margins. You see it in our spot day rates. You see where we've had the type of resiliency that John gave you some detail on earlier. I've got a lot I'd like to say on that.

We're not really going to talk a lot about our pricing strategy on this call, but I do think that we're focused on the type of returns we're generating. And again, we believe that the market is improving. So we thought it was ill-advised for competitors to try to deeply discount even their top-tier rigs, just in order to try to capture some activity. The delta between our activity today and their's is still significant. So I'd better stop before I say more about our pricing strategy, because that's a competitive secret of sorts.

Sure. Sure. Understood. Okay, well, thanks a lot, Hans.

Brad Handler, with Jefferies.

Thanks. I'm sorry. I tried to de-queue, but my questions have all been answered. Thanks guys.

Ryan Fitzgibbon, with Global Hunter Securities.

Hey. Good morning, guys. Thanks. John, if I could touch on some of your commentary. You mentioned that your fleet mix holds unchanged here, that average fiscal '14, day rates would decline by about 2%, relative to Q3. If we see them cost holds unchanged at $12,900, are you more or less guiding for margins to get to mid to upper $14,000 per day range next year?

Well, we we're trying to just give a theoretical picture, because sometimes it's less clear on the impact of the term contracts and the rolloff and how that pricing varies.

Yes. This is Juan Pablo, and Ryan, I think your assumption is, in general, correct. That a couple of percentage points on the revenue per day number would represent the delta that you described, having an impact on our average rate margins per day of $500, $600, $700 or so. But that is only a theoretical scenario. It's not--we're not providing guidance, and it's not really, at this point, our expectation that we would be flat spot day rates through the end of fiscal '14. We certainly hope that they improve, as a matter of fact. But nonetheless, we wanted to provide you a sense of what would happen if spot pricing would remain more or less flat through the end of fiscal '14 and utilization levels would remain more or less where they are today. Hopefully, that's helpful.

No, that's helpful. I appreciate that, good color. My follow-up question would be, John, you also mentioned some opportunities, maybe internationally. You're cautious, but are you expecting anything to materialize next year, whether it be in the Middle East or Latin America, based on the tendering activity you've seen?

Ryan, we're participating in several tenders. And you've followed us long enough, you know where there's been some frustration on our part that we haven't grown internationally more quickly than we have. Particularly when you consider the performance that FlexRigs have had in the areas that they've worked. Again, we're hopeful, and I think, particularly most recently, in the Middle East. The performance that the Flex3s have had and the Flex4s have continues to have, I think there's been some eyes opened on what's possible.

We still have the challenges that are there, so our hope is that we can work through those challenges. And then, we have one Flex3 working in the Niocan area in the shale play. A Flex3 that's done a very good job. And again, our hope is that that will also open up some opportunities for us. But as far as any in particular and trying to nail a number on whether it's three rigs or 10 rigs, it's really hard to say at this stage.

Okay. Appreciate the color. Thanks, guys.

Michael LaMotte, from Guggenheim.

Hey, guys. John, if I could follow-up on the pad issue. Earlier this week, Haliburton commented that they thought upwards of half of the rigs in the major sales were working on pad now. If I think about the competitive advantage of AC over older SCRs, one is, obviously, the mob time and two is the ROP. Does this rapid move--I guess, first of all, would you agree with that number? Then secondly, with such a rapid uptake, has the competitive advantage of ACs over SCRs on the mob front been adversely impacted? And I'm wondering if once we reach a saturation point, if the ROP isn't an accelerant for substitution again?

Well, if I understand your question, first of all, I think--it's hard. I don't think we have enough information to know if 50% of the industry. In our own particular case, we're around 50% in the unconventionals in our pad drilling application. There's no doubt the AC, at least with our fleet, FlexRig3 is going to move quite a bit faster than a conventional SCR rig. We're going to, in some cases, move in half of the time. So in the case where you add a pad system to a conventional rig, then, yes, it improves its overall well cycle on the rig move segment significantly. But--and so, it's going to have maybe a greater impact than adding a pad system to say, a FlexRig3.

On the other hand, that's really only 10% of the time on a well. And so, the drilling piece of the well is going to be--just the drilling performance, and you said penetration rate. I'm going off top of my head. But I'm going to say, depending on the area, that's 25% to 35% of the well. But there's a lot of other factors included in the total well cycle besides penetration rate that AC-Drive rigs provide.

Our FlexRigs are going to run casing more efficiently. They're going to nipple up and test more efficiently. There's a lot of aspects. That kind of goes back to this designing a rig with a clean sheet of paper, and not just looking at the technology of AC-Drive, but also looking at the other aspects of what make up title cycle time savings in a full well cycle. Rig move is one of him. Drilling time is one of them. The other things that I mentioned, as well as others that make up that time savings.

So what we see is, obviously, a lot of energy around the pad drilling application. And I can understand that. And particularly as you're looking at it from an SCR owner's perspective. There's a lot of advantages there. But there's a lot of other things that are captured in the course of the well cycle that we remain pretty excited about.

That's great color. Thank you. And then, as I think about 20 to 22 idle rigs, a fleet your size, with as much activity as you have in the spot now and contracts rolling over, how should we think about sort of frictional dynamics, and what true max utilization on a fleet your size in spot versus term mix?

Yes. That's a great observation. 20 or 22 rigs, we're at 92% utilization. The industry, they see rig count--I want to say today is around 86%. You take H & P out of the equation, the overall AC utilization obviously is going to be less than 86%. When you take those 20 rigs and you consider four of those are in California, so those are a little stranded, to a certain extent. Then you've got a couple of other rigs, and so, you spread the remaining 18 over nine basins. That doesn't give you a lot of excess capacity, when you think about it in those terms.

So Hans alluded to it. We're not concerned about it. We're not panicking about it, yet we'd love to put those rigs back to work. I think we will. And really, we have.

Over the course of the last nine months, we've continued to put rigs that are stacked back to work, but we've also had rigs released that we didn't expect were going to be released, that then went into stacked mode. So that's kind of what you're seeing. We have described it as turn. Your comment of using frictional unemployment as an example. On the people side, frictional rig unemployment. I think it makes a lot of sense.

Okay. On emerging basins, are you seeing any accelerated interest in rig demand for the Utica or maybe some of the MidCon liquid plays?

We've had discussions, and I can't think of the specific examples in the Utica, but there have been some discussions. But I don't see any dramatic growth there. I'd say our largest growth potential, at least for the foreseeable future, is going to be the Permian. But there has been some discussions in the mid-continent, in Oklahoma. Those discussions shouldn't be a surprise. Those discussions are surrounded mostly around--we've got these old mechanical rigs, that put out a 1,000 horsepower that take six, seven days to move. Flex3 can move in three days.

So obviously, there is a hurdle there on the day rate, but the numbers work. And so, I think as we begin to get more uptake on that, I think we've got some opportunities to high grade on some rigs. The other thing I didn't talk about in my prepared remarks is the new customers. And you've heard us talk about this in the past. We've got a lot of really--we've got a lot of really great new customers, and we also have a lot of new customers that happened to be small independents. And those are the--those guys that are typically using some of the older rigs, and they've begin to use FlexRigs. So that's been exciting to see. It doesn't make up a real large number of rigs, but I think what it does portray is there's a value proposition realization, and that you can pay more for a rig if you are getting the value proposition that we talk about.

Okay. Thanks so much.

Waqar Syed, with Goldman Sachs.

Thank you very much. John, we hear about a trend of H & P bringing in smaller rigs to drill the vertical section of the well in the Eagle Ford and them let the T-1 kind of rigs drill the horizontal sections. Are you seeing that, and how pervasive is that?

Waqar, that's been a--I can remember probably 2006, 2007 when operators couldn't get rigs and they would utilize that for a different reason. Our position has always been and actually when we've talked to customers that have tried it, is the numbers from a cost perspective, the numbers don't work. If you really think about it, you've got two rig moves. The rig that you're bringing in that's small, drilling the surface, or the surface or the intermediate. If it's intermediate, that rig is going to be very inefficient. Again, that's comparing it to say, a FlexRig3.

In a lot of cases, we're going to drill that intermediate section of the hole in half the time. The only time I would think that it makes sense, and again, I'm using historical perspective, is if you just can't get access to the rigs, and you're holding production, or you're trying to get ahead of the curve in that respect. I'm not aware of that happening today in the Eagle Ford, and I'm not aware of any of our customers doing that. Now, if you're talking about pre-setting surface, and again, service could be 500 feet or 1,500 feet, then that's a different animal. That--we do have customers that are doing that, and that makes a lot of sense in some cases.

Yes. We've seen, if you look at the Baker Hughes rig count and they break it out in the basins. In the Eagle Ford, we have seen the directional rig count has gone from one or two rigs to 35, 36 rigs in the space of about five or six months, and one horizontal rig count has come down. And we've tried to think about any explanation for that. I don't know if you've looked at that data, if you have an explanation of why and what is that trend is about?

And what--how did you describe the--you said--I didn't hear what you said on what type of rig?

The directional rig. They--in the Baker Hughes rig count, the breakup in the East basin, the rig count between the vertical and directional, and then horizontal. And what we've seen in the Eagle Ford is the directional rig count is gone from one or two about 4, 5 months ago to about 35. And at the same time, the horizontal rigs count has come in a little bit. And so, we were trying to figure out what that 35 rig count increase is. And one explanation was maybe people are bringing in smaller rigs to drill the vertical section, or it may be the directional section. But I don't know if you've looked at that, and if you have an explanation for that.

I don't know that we've noticed. But I was curious. Is--are those wells, those directional that they're naming directional, are they drilling--still drilling oil wells?

That is correct, yes.

Yes. I don't have an explanation for that. I guess--

Okay. The other thing is if you look at all of the growing basins, the major basins, one of them where you don't have good penetration of Tier One AC rigs is the Mississippian. And it's been dom--traditionally predominated by private drilling contractors with a lot of mechanical rigs. I don't know if you were referring to that basin or others, but are you seeing any change there, in terms of operator behavior and leaning towards more of these Tier One rigs?

You know, when I think about the Mississippian, obviously, it's a different formation. But from a depth perspective and lateral, it had a lot of similarities with the Barnett. And if you recall, the Barnett early on was dominated by mechanical rigs. And over time, you saw what happened. The mechanical rigs, for the most part, went away. And AC rigs, and there were a lot of upgraded SCR rigs.

But I think, by far, the AC rig market dominated in the Barnett when it was really active. So that would be my expectation. I guess part of the question is, do the laterals get longer? How efficient are the rigs? Are they doing pad drilling?

Or are they doing single wells? I think it'll change over time. Our rig count's grown in the Mississippian over the last couple of quarters. So--but your point's a good one, as far as the types of operators. I am not particularly aware who the others are.

Okay. And then, final question. If you would care to comment on your outlook for the overall industry rig count by the end of the year? Do you--what kind of growth, or no growth do see by late this year? And then, maybe even for next year?

Waqar, this is Hans. You know that topline, kind of headline, rig count number becomes less and less relevant. And as you track the different segments, the two underperforming segments continue to lose share. And AC, even in a kind of softer market, continues to gain. So you're also going to have efficiency as a factor.

And I mentioned, operators are getting more bang for their buck. That, in our mind, is not a bad thing. Efficiency's not the enemy. Efficiency is what helps differentiate our offering from the group. So we're focused less and less on that number.

I think it could still edge up, with oil prices over $100. And I don't think it's a '13 event, but I think it doesn't take a lot of positive things to happen on the natural gas front to see it having a factor in 2014, and certainly in 2015. It's set up nicely. So we're overall encouraged on those things, but we would encourage people to watch the subset of what's happening with the AC count, what's happening with horizontal drilling. And that's what probably they should be paying more attention to.

But the horizontal rig count is actually being the one that's being kind of weak. Year-to-date, it's been coming down. And that's probably because of efficiency gains. Do you see that trend continuing?

I think that's a short-term phenomenon. I think it ends up--more and more customers and more and more plays are trying to expose more and more well bore. And you do that by going horizontally.

Okay. Thank you very much.

And this is Juan Pablo. If we do have more questions, perhaps we have time for one more.

Walt Chancellor, with Stephens Inc.

Hi. Thanks for fitting me in. Had a quick question, regarding the Q4 US drilling guns. On the average rig revenue per day number, is that inclusive of the $7.7 million in early termination, and then the $5 million in delivery delay revenues?

No. It is not.

Okay.

That is a good question. Thanks for clarifying that.

And then, that--and then, would on an as reported basis, would both of those get captured in the drilling segment in that figure?

Yes, they will.

Okay. All right. Thank you very much.

Thank you very much, everybody. Have a good day. Good bye.

This concludes today's conference. You may now disconnect your lines, and have a wonderful day.