Good day, and welcome to the Third Fiscal Quarter Earnings Conference Call. [Operator Instructions] 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 U.S. Private Securities Litigation Reform Act of 1995, all forward-looking statements made during this call are based on current expectations and assumptions that are subject to risks and uncertainties as discussed in the company's annual report on Form 10-K and quarterly reports on Form 10-Q. The company's actual results may differ materially from those indicated or implied by such forward-looking statements. We will also be making reference to certain non-GAAP financial measures, such as segment operating income and operating statistics. You may find the GAAP reconciliation comments and calculations on the last page of today's press release. I will now turn the call over to Hans Helmerich.

Thanks, Juan Pablo. When you consider the challenging nature of the U.S. 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 other 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 are willing to return excess cash to share owners, but also reflects a confidence looking forward and our ability to pursue in 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 1/2 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 in 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…

Thank you, Hans. Strong results from drilling operations under the very difficult quarter were primarily attributable to even better-than-expected performance in both the U.S. land and international land segment. 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 operation, 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 a recently increased regular dividend, some debt that is due this year and income taxes corresponding to the recent sale of investment securities. Our effective income tax rate for continuing operations for the first 9 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 pretax 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 U.S. 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 1 year ago, we had -- we delivered 30 new build AC drive FlexRigs to the U.S. 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 U.S. 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 U.S. land segment where our U.S. 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…

Thank you, John. And Tasha, we will now open the call for questions.

[Operator Instructions] We'll take our first question from Jim Crandell from Cowen.

My first question has to do with new builds and it has to do both in the U.S. 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 that you're taking or it's just by chance and you'll reestablish leading market share as we go forward?

Thanks, Jim. Well, first, we know very little bit about some of the points you bring up in terms of what the day rates are length of the term, construction cost. 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 1 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 place and 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 build cadence serves kind of 2 purposes. One, it gives us the optionality for capital spares but it 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 the rig cycle, typically, you absorb some of that overhang or some of that capacity, and then you begin to have customers interested in focusing on the type of rigs that they want. And that's where we think we'll see some attractive new build opportunity. 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 S22, we would expect those rigs to be taken up in an improving environment and then that would lend itself to additional opportunities for new build. 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 Flex 3 and that you'll see new builds because they really want the advanced capabilities of the FlexRig6?

I think, you're talking about the Flex 5.

5. I'm sorry, I'm not familiar with next generation.

I'm glad you have that anticipation. Yes, I think that 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've 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 a leading role in that. I mean, 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 just from 40%, to, I think, 38%. At one point, I suppose we hit 100% of that market share. But 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.

Okay. And one last quick one. Hans, do you -- 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 advance of LNG 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 it 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 pool basis. We're not going to go in and try to buy up some market. If we have customer sponsorship and some of our larger customers would want to sponsor us somewhere like Canada or elsewhere, then we have interest in that. So we'll just see how it plays out.

Okay. And you can be -- John, do 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 U.S., 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 don't want to leave you with the impression that this is 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.

We'll move next to Kurt Hallead from RBC Capital Markets.

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 do you think the pricing dynamic is for these long-term contract commitments that you're ready to discuss? And can you give us some 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 shifts the 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 ballpark. But again, there's a lot of range there, depending on the operating area. Is it a winterized area, is it not a 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 our own from that respect because of our performance. Did I answer your question? Was there more color you wanted there?

Yes, I think. Yes, I wasn't quite sure on that leading-edge in the mid-20s, is that more of your contract dynamics? Or you were 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 -- again, it's going to be dependent 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 sense of urgency for putting new rigs to work or the increased drilling efficiency, however you want to put it, what's your sense on how your customers are looking at spending plans in the second half of the year. Do you get a sense that given the recent bump, and you indicated in your press release, but with the recent bump in oil prices, are you already getting an indication, Hans, that E&P 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 has been off of plan 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, 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, Kurt, into an emboldened outlook for the rest of this calendar year, and then, certainly, will get some momentum going, assuming commodity prices hold, get some momentum going into '14. So I think that we're hearing a more upbeat sense from our customers and discussions.

We'll take our next question from Byron Pope with Tudor, Pickering, Holt. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Your rig count 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 count, let's say, over the next 12 to 18 months in the Permian, does it have any notable implications for your overall fleet average day rates and margins? I'm assuming the answer is no, but I'd just like to hear your thoughts on it.

Yes, Byron, this is John. I think, the -- probably, the rig of choice has probably been the FlexRig3, and in some cases, there is a pad application. Most cases, at this stage, there isn't, but there are some pad applications. We have the FlexRig4, super single that we have, I think, almost all of those in the U.S. are working in the Permian. And that's been a real popular rig design as well, and 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 FlexRig3, 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. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And then, just a second question for me. Juan Pablo, you mentioned the fiscal '13 CapEx budget is $890 million roughly. Materially, to say, given that we're approaching the end of your fiscal year kind of directionally, how you guys are thinking about fiscal '14, just thinking directionally, does it feel higher, flattish, lower year-over-year?

Well, we will be talking more about that during our next conference call. 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 talk about that, Byron, sorry.

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. But again, we're still a little bit early on as much as the pad drilling as we've seen as an example in the Eagle Ford or the Bakken. But I do think we'll have FlexRig5s. As that market matures and goes to more pad drilling, I think, we'll see that happen.

We'll take our next question from Dave Wilson with Howard Weil.

First, just wondering on rig efficiencies and how much is left out there? Is it just a matter of the industry more fully deploying 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 maybe to the sidelines sooner rather than later?

I'll let John do some of that, but yes, I think, the sense of your question is right. But the bar just gets placed higher and higher and as you have more horizontal drilling, 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 Flex 3s and now Flex 5s 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 that 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 and 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 something to that?

Well, 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 the SCR rigs are going to be the bottom of the barrel, right? I mean, they're going to be the lower-end performers. So from just an 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 basis, let's just use the Flex 3 as an example, we continue to see, even with all the improvements that we've seen over the last 3 years, we continue to see improvements in 2013. And as we've 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 on the field, there's still quite a bit of opportunity, I think, ahead for us.

Okay. Great. And then, just kind of sticking with the efficiency theme here, on the cost front, 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? Are you thinking you're better than that? Or is that going to kind of reach the kind of technical limit there as well?

Well, I think, we've been a little lower in previous quarters, but the variables change quarter-to-quarter. Again, in some previous quarters, we hadn't stacked as many rigs and then reactivated as many rigs. So there's 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 2 or 3 years ago. And so, obviously, when you're running equipment harder, equipment wears out more quickly, you go through more expendables, which drive cost up. And so that's -- part of our message and part of what Hans talked about earlier is our efficiency gains, we're also working to what we know or how do you maintain a better cost structure, how do you maintain a better maintenance schedule in order to drive your operational cost. 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 $12,900 plus or minus 1% to 2%, based on what we know right now, I think, makes a lot of sense. We have had some quarters in the past year, 1.5 years, I think, that we were slightly under the $12,700, but I don't see us going to those levels right now.

David, the only thing I would add to that is I think it's a real accomplishment of our folks, and you 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.

We'll take our next question from Robin Shoemaker from Citigroup.

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 2 back in April, and I think 3 in January. So anyway, I think, the right number is 5 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 that you have now of 2 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, is you have some misinformation out there. One of our peers this week talked about that we had only announced 8 new builds under long-term contract since the first of 2012, when, in fact, the number is much higher at that 17. And 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 have 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 2 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 0 spares for so long because we could pull them out of our manufacturing queue that we're still in that phase. We're unitizing capital spares and we're having, in effect, the ability to either support a growing and 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 with say, we're very comfortable with building 2 rigs per month through the end of the year. And we can continue to watch that and monitor that and we look at that. We're doing that because we think the market is 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 a long-term contract. And so we'll bide our time. We'll be patient. We hope the market trends that way. We think it will, but I think we're in a good spot right now.

Okay. So on the 22 idled FlexRigs that you mentioned, clearly, there's a trade-off there. You probably could put it all back to work at a lower price. You're defending a price level, so would that be the strategy is just say, okay, here's a level 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. And you 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 theirs is still significant. So I better stop before I say more about our pricing strategy because that's a competitive secret, of course.

We'll move next to Ryan Fitzgibbon with Global Hunter Securities.

John, if I can touch on some of your commentary. You mentioned that your fleet mix hold is unchanged here that average fiscal '14 day rate would decline by about 2% relative to Q3. If we assume cost hold unchanged at, call it, 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 were trying to just give a theoretical picture because, sometimes, it's less clear on the impact of the term contracts and the roll-off 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 of having an impact on our average rig margin 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 is that we will see flat spot day rates through the end of fiscal '14, we certainly hope that they improve as a matter of fact. But nonetheless, we just 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.

That's helpful. 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 activities you're seeing?

Well, Ryan, we're participating in several tenders. I mean, you've followed us long enough, you know that 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 has 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 Flex 3s have had and the Flex 4s have continued 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 Flex 3 working in Neuquén area in the shale play, a Flex 3, 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 3 rigs or 10 rigs, it's really hard to say at this stage.

Our next question comes from Michael LaMotte from Guggenheim.

John, if I could follow up on the pad issue. Earlier this week, Halliburton commented that they thought upwards of half of the rigs in the major shales were working on pad right now. If I think about the competitive advantage of AC over older SCRs, one is, obviously, the move time and two is ROP. Does rapid move -- I guess, first of all, would you agree with that number? And secondly, with such a rapid uptake, has the competitive advantage of ACs over SCRs on the move front been adversely impacted? And I'm wondering if once we sort of 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 didn't 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, or 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, we're going to move in half the time. So in the case where you add a pad system to a conventional rig, then yes, it improves its overall well cycle from the rig move segment significantly. 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 -- they're 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 cycle time savings in a full well cycle. Rig move is one of them, 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. And then, as I think about 20 to 22 idle rigs, with 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 the fleet of your size is? And spot versus term mix?

Yes, that's a great observation, 20 or 22 rigs. We're at 92% or a little 92% utilization. The industry's AC 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 4 of those are in California, so those are a little stranded to a certain extent, then you've got a couple others rigs and so you spread the remaining 18 over 9 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. Yes, we'd love to put those rigs back to work. I think we will. And really, we have. Over the course of the last 9 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 stack mode. So that's kind of what you're seeing. We've described it as churn. Your comment using frictional unemployment as an example on people sizes, 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 Utica or maybe some on the mid-con liquids plays?

We've had discussions, and I can't think of 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, it's about 1,000-horsepower, that take 6, 7 days to move, FlexRig can move in 3 days. So obviously, there's the 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 great new customers and we also have a lot of new customers that happen to be small independents. And those are the guys that are typically using some of the older rigs and they begin to use FlexRigs. And so that's been exciting to see. And it doesn't make up a really large number of rigs but I think what it does portray is that there's this value proposition realization and that you can pay more for a rig if you're getting the value proposition that we talk about.

We'll take our next question from Waqar Syed from Goldman Sachs.

John, we hear about a trend of E&P bringing in smaller rigs to drill the vertical section of the well in the Eagle Ford and let the Tier 1 kind of rigs drill the horizontal sections. Are you seeing that? And how pervasive is that?

Waqar, that's been -- 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. I mean, if you really think about it, you've got 2 rig moves, the rig that you're bringing in, the small drilling surface or the intermediate, if it's intermediate, that rig is going to be very inefficient. Again, as comparing it to, say, a FlexRig3. In a lot of cases, we're going to drill that intermediate section of a hole in half the time. The only time I would think that it makes sense, and again, I'm using a 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, I'm not aware of any of our customers doing that. And if you're talking about free-setting surface, and again, surface 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 like if you look at the Baker Hughes rig count and they break it down in the basins, in the Eagle Ford, you've seen that the directional rig count has gone from like 1 or 2 rigs to about 35, 36 rigs in the space of about 5, 6 months, and 1 horizontal rig count has come down and we were trying to think about any explanation for that. I don't know if you've looked at that data and if you have an explanation of why, what is that trend 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, in the Baker Hughes rig count, the breakup in these basins, the rig count between vertical, directional and then horizontal, and what you've seen in the Eagle Ford is the directional rig count has gone from like 1 to 2 about 4 or 5 months ago to about 35. And at the same time, the horizontal rig 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 maybe a little directional section. So -- 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 if are those wells, those directional that they're -- are they still drilling oil wells?

That is correct, yes.

I don't have an explanation for that, I guess.

Okay. The other thing is if you look at all the kind of growing basins or major basins, one of them where you don't have good penetration of Tier 1 AC rigs is the Mississippian, and it has traditionally been dominated 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 1 rigs?

When I think about the Mississippian, obviously, it's a different formation, but from a depth perspective and lateral, it has 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. And 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 does the laterals get longer? How efficient are the rigs? Are they doing pad drilling? Or are they doing single wells? I think, it will change over time. Our rig count has grown in the Mississippian over the last couple of quarters. So -- but your point is a good one. As far as the type of operators, I'm not particularly aware who the others are.

Okay. And then, just 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 you see by late this year? And then, maybe even for next year?

Waqar, this is Hans. As you know, that top line kind of headline rig count number becomes less and less relevant. And as you track the different segments, the 2 underperforming segments continue to lose share in 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 is 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 '15, 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 been 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 is a short-term phenomenon. I think it ends up -- I mean, more and more customers and more and more plays are trying to expose more and more wellbore and you do that by going horizontally.

If we do have more questions. Perhaps we have time for one more.

We actually just have one question left. We'll move next to Walt Chancellor with Stephens Inc.

I just had a quick question regarding the Q4 U.S. drilling guidance. On the average rig revenue per day number, is that inclusive of the $7.7 million in early termination? And then, $5 million in delivery delay revenues?

No, it is not. Yes, that is a good question. Thanks for clarifying that.

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

Yes, they will. Thank you very much, everybody. Have a good day. Goodbye.

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