Good day, everyone, and welcome to today's program. [Operator Instructions] Please note this call will be recorded. [Operator Instructions] It's now my pleasure to turn the call over to Juan Pablo Tardio, Vice President and CFO. Please go ahead, sir.

Thank you, and welcome, everyone, to Helmerich & Payne's Conference Call and Webcast corresponding to the first quarter of fiscal 2012. With us today are Hans Helmerich, Chairman and CEO; and John Lindsay, Executive Vice President and COO. As usual, and as defined by the U.S. Private Securities Litigation Reform Act of 1995, all forward-looking statements made during this call are based on current expectations and assumptions that are subject to risks and uncertainties as discussed in the company's annual report on Form 10-K and quarterly reports on Form 10-Q. The company's actual results may differ materially from those indicated or implied by such forward-looking statements. We will also be making reference to certain non-GAAP financial measures such as segment operating income and operating statistics. You may find the GAAP reconciliation comments and calculations on the last page of today's press release. I will now turn the call to Hans Helmerich, Chairman and CEO. And after Hans, John Lindsay and I will make additional comments, and we'll then open the call for questions.

Thanks, Juan Pablo. Good morning, everyone. As the company continues to grow, we hit 3 notable milestones for our most recent quarter. We recorded our all-time record level of income from continuing operations. We also reached our best-ever levels for revenue and rig activity for the last quarter. On this call, we will detail some of the drivers that enabled this performance and walk through some of our expectations going forward into 2012, including some moderation in the second quarter as daily expenses returned to more expected levels from this quarter's significantly reduced number. Before that discussion, let me comment for a moment just on the dire state of the natural gas market. Prices are plummeting. We see storage overflowing and an ample behind of pipe supply, so the question becomes how much downward pressure may this bring to bear upon the domestic land drilling market? Clearly, a combination of these factors in previous cycles would have resulted in a predictable drop of the rig count. In fact, for decades, natural gas pricing was the single most important barometer for the overall rig count. Today, oil and liquids-rich gas have transformed the domestic drilling landscape. Oil-directed drilling has been on a steady march up, while dry gas drilling has lost ground. And while the gas-directed count will even now most likely accelerate its decline trend, many expect any fall out to be partially or fully offset by displaced rigs being redirected to oil and liquids-rich targets. This transition that has been underway since the summer of 2008 and may well become more pronounced and impactful. It has been combined with the transition towards more complex well design and higher performance rig requirements. We would expect higher-performing Tier 1 AC drive rigs will be best positioned to make the transition while…

Thank you, Hans. As announced earlier today, the company reported $144 million in income from continuing operations for the first quarter of fiscal 2012, representing an increase of almost 20% as compared to the immediately preceding quarter. This very significant increase was mainly attributable to our U.S. land segment, where we experienced continuing improvement in pricing and activity levels and a very favorable reduction in daily rig expenses. As Hans mentioned, our U.S. land daily rig expenses are expected to return to a normalized level during the second quarter. Nevertheless, we do expect continuing overall growth in revenue and rig activity as we transition to the second fiscal quarter, primarily as a result of an increasing number of FlexRigs in our U.S. land segment. Our capital expenditures estimate for fiscal 2012 remains at approximately $1.1 billion. Our depreciation and our general and administrative expense estimates for the year also remain at approximately $380 million and $105 million, respectively. Interest expense after capitalized interest is now expected to decrease to approximately $13 million during fiscal 2012, and our tax rate for continuing operations during the year is expected to be approximately 37%. I will now turn the call to John Lindsay. And after John's comments, we will open the call for questions.

Thank you, Juan Pablo, and good morning. My comments will be on the operational results for our first fiscal quarter 2012 for our 3 operating segments, U.S. land, offshore and international, as well as the outlook for the second fiscal quarter of 2012. And I'll begin with our U.S. land segment first fiscal quarter results, where U.S. land operating income increased 17% sequentially to $225 million as the U.S. land segment took delivery of 11 new build FlexRigs during the first fiscal quarter. Revenue days increased 5% to 20,968 days, representing 228 average active rigs in the first quarter. An average of 145 rigs were active under term contracts and an average of 83 rigs were active in the stock market. Average rig revenue per day increased by $312 to $26,861 per day. Average rig revenue per day for rigs working on term contract during the first fiscal quarter was approximately 5% higher than average rig revenue per day for rigs working in the spot market. Average rig expenses per day decreased by $643 to $12,292 per day, primarily as a result of what we believe were only temporary reductions in maintenance and supply costs. Consequently, average rig margin per day increased by $955 to $14,569 per day. The outlook for U.S. land during the fiscal quarter remains positive. H&P remains the most active U.S. land contractor as we have 236 contracted rigs today and 23 idle rigs, a 91% utilization rate. Of these 236 rigs, 152 are under term contracts and 84 are in the spot market, including 82 FlexRigs. Of the rigs in the spot market, 63 are drilling in areas that typically target oil and/or liquid-rich gas. In the second fiscal quarter of 2012, we expect revenue days to increase by approximately 2% to 3%. Based on…

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

[Operator Instructions] We will take our first question from William Conroy of Pritchard Capital.

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

Sure, William. Right now, we're probably 8 or 9 months out as far as our next new build delivery slot that would be available. We have quite a few conversations still ongoing with customers regarding some of those new build slots. Most of those conversations are in the calendar year 2012. Occasionally, we'll have some discussions regarding 2013. I really think what's driving it is much of what Hans and I tried to portray, which is the complexity of wells and how those wells are changing over time. And especially now, with some softness in dry gas basins, you're seeing rigs being redirected quite often. And in a lot of cases, on the lower-end rigs, I think what we're seeing is a lot of those rigs are getting stacked because they're not getting moved because of the costs associated with moving them as well as just the overall performance. So we believe that if you look at the overall market in terms of available AC drive rigs, we think there's opportunities to continue to add. And again, I think the biggest challenge right now is that we're about 8 or 9 months out.

We'll take our next question from John Daniel with Simmons & Company. John M. Daniel - Simmons & Company International, Research Division: Just really one for me this morning. I understand the theory about the new rigs displacing the old rigs, but I would assume that some of those old rigs don’t want to go quietly. And so at this point, have you seen any price discounting by your peers? And if not, at what point do you expect the price discounting to begin, and then how would that influence your pricing strategy?

This is Hans. And I don't think we're seeing that yet in full force. But if you go back coming off of last downturn, what developed is a pretty clear bifurcation in the marketplace and there was discounting, as you inferred, from those lower-performing rigs. So we would expect that, that could happen and they won't go quietly. We've seen, again coming off of that downturn, the higher-performing rigs get taken up quickly and the activity has been very strong across-the-board, not just with our tier 1 rigs but with our peers. And so kind of to the first question and to your question as well, I think that there'll be a transition time and the market will absorb some of those. I mean, we've just come off -- I wouldn't read too much into our 3-rig announcement. We've just come off the holidays and kind of the turmoil around gas prices, and I think the market will take a certain amount of time to settle down. But I don’t think the longer-term trends towards a replacement cycle really get pushed to the side. I think that's something that continues to run going forward. John M. Daniel - Simmons & Company International, Research Division: Okay. But is it safe for me to assume then, Hans, that as you look at the market today, that it's reasonable to assume that as we get towards the back half of the year, all else being equal, that pricing begins to trend lower?

Well, I guess I'm a strong believer in the segmentation of the business and that we've seen it. There was some question going into this last recovery in '10 and '11, would there really be a differentiation and a segmentation? And in fact, there has been and you've seen the pricing related to that. So the notion that there's this drag effect, I think that may happen just on the margin because I really think the customer is determined to have the right equipment matched with his development and exploitation challenges. And I just think that the segmentation becomes very clear and it won't have the contamination or contagion that you might expect.

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

Waqar, we can't hear you. Are you there? [Technical Difficulty]

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

Waqar, that's a good question. This is Juan Pablo. We had approximately $187 million of deferred income taxes in fiscal 2011. And our best guess at this point is that we have a similar amount during the year distributed throughout the 4 quarters, perhaps the first quarter, may be a little higher than the other ones. But it's hard to tell by how much.

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

Waqar, I think what we're seeing is a much more orderly and smooth transition in this market going forward than what we all lived through from the fall of '08 into early '09. And I think that was more related to the financial crisis and a boardroom decision of wanting to make sure companies preserve their liquidity and just trying to create links to secure that. So I think this is more of a normal orderly process. And it's why, I mentioned to John, I don’t think it will have a huge drag going forward on pricing. And again, we're hoping that -- we've really been in this transition since the gas-directed rig count peaked in July of 2008. So I think companies look at it in a fresh way, trying to project gas prices and then the combination of things. But as we mentioned, we're encouraged by just the sheer inventory level, especially the customers represented in our customer roster have to redirect towards oil and gas liquids-rich drilling. So that's where I think some of the order comes in and the smoothness in the transition.

Okay. You've mentioned – you’ve probably mentioned before as well, and I was kind of -- I joined in late, but would you say about 30% of your rigs are currently working into basically just the dry gas plays, is that right?

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

Waqar, this is John. Another example. If you look at the Haynesville, I think at our peak, we had 28 rigs working in the Haynesville. Today, we're down to 5 or 6. But all of those rigs and most of those 28 were on term contracts. And those rigs have all been moved to either the Eagle Ford, the Permian or the Cana Woodford. None of those rigs were stacked. I mean, essentially the customers were using the best rigs in the basin they can make the most money with. And so I think that's what we're going to -- as Hans alluded to, I think that's what we're going to continue to see is the best rigs being mobilized to the basins where the economics are the best.

So one other question just on a big picture. When we look at the rig count in the U.S., by our estimates, about 70% of all drilling right now, if not more, is on oil and liquids-rich. And there is very little limited dry gas drilling going on and only in maybe the Haynesville. Notice Marcellus, there is some rigs, in any meaningful way, that are drilling for dry gas. Rest of the places like the Barnett, Fayetteville and others, there are very few rigs that are drilling. And so even if you cut them by 50%, the impact is not that huge on the overall rig count. Do you see it that way as well? Or...

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

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

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

We'll take our next question from Scott Gruber with Bernstein Research. Scott Gruber - Sanford C. Bernstein & Co., LLC., Research Division: Hans, you've discussed the outlook for additional FlexRig orders in the U.S. But with interest in some shale development programs progressing now down in Latin America, we do have established positions. Is there a potential for international FlexRig orders to begin complementing domestic orders possibly later this year? Or is that still off the horizon?

Well, I think the answer is we hope to see and I think we will see and we're having conversations with customers about adding to our FlexRigs into the international part of our fleet. And then it gets back, Scott, to exactly what you're kind of focused on, is that an end of 2012 event or '13 event. And our thought is it's a '13 event. But tough to predict. I said recently that we have seen less focus and interest from our customers recently than we had 6 or 9 months ago. But I think coming off of the holidays, we're starting to have some additional conversations and talks. So that kind of ebbs and flows. But I think you should focus more on it being impactful later in '13 than later in '12. Scott Gruber - Sanford C. Bernstein & Co., LLC., Research Division: Okay, so that would be a 2013 delivery of equipment or 2013 placement of the orders for FlexRigs?

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

We'll take our next question from Brad Handler with Crédit Suisse. Brad Handler - Crédit Suisse AG, Research Division: A couple of follow-up questions, please, around your cost guidance, just want to make sure I understood it. It sounds -- you mentioned a $500 a day labor increase. Is that fully implemented in the second fiscal quarter?

Yes, Brad. It will be fully implemented in the second quarter. Brad Handler - Crédit Suisse AG, Research Division: Okay, so there's $500 a day on average. I think you mentioned $12,700 a day average expense per day guidance, is that right?

Well, the $12,700, Brad, is really a reference to a more normalized cost like what we've seen over the last couple of quarters. And as we said, it's hard to nail the number right now, but that's kind of the range that we're thinking. But we spent -- every quarter, we spend a lot of time and effort on trying to work on costs and controlling costs and working on a lot of different systems and processes. And this quarter turned out very, very nicely. We'd love to see the next quarter turn out nicely. But I think we have to take into account what the -- kind of what average has been, so that's why we're talking that $12,700. Brad Handler - Crédit Suisse AG, Research Division: I think I see. I'm just -- if you were at $12,300 and you add for labor, it doesn't sound like you're anticipating any of those lower maintenance or lower supply costs to go away this quarter. In other words, you might be able to keep that lower level of cost. Am I -- I'm just -- I don't want to make too much of numbers that I think maybe you're saying are indicative, but that's -- is that what you're suggesting for us?

Brad, this is Juan Pablo. I think that $12,700 level that was mentioned excluded any increased expenses that would be passed through to customers through increased day rates. And so the $12,700 would be the base, and then the $500, and if there are any other pass-throughs, would be additive to that. Brad Handler - Crédit Suisse AG, Research Division: I see. Okay. All right, I think that clarifies it. Great. Second question, unrelated. Maybe just help me understand something a little better. If you have a rig that's on term contract and you mobilize it to a different basin, presumably a liquids-rich basin, what happens to the expenses of that mob [mobilization]?

Brad, this is John. Those expenses are contractually covered by the customer. And so whatever the mob cost is, we're kept whole on that. And likewise, if you were to move from a lower-cost basin to a higher-cost-per-day basin, as it relates to labor and maintenance and supply, we would also have that pass-through as well. So we're kept whole on our margins. But likewise, if you went from a higher cost to a lower-cost basin, then you would also adjust that day rates accordingly. Brad Handler - Crédit Suisse AG, Research Division: Sure. So the individual expense, if there is transition to take place, we might expect reimbursables to go up on the revenue base over, say, the next couple of quarters? Is that reasonable?

Well, that is true. I don't know that it's necessarily true that we're going to have a large movement of rigs. As I mentioned earlier, we've gone from, I believe, 28 rigs in the Haynesville down to 5 or 6. I think we'll continue to have rigs migrate out of basins, but I don't think there are going to be a lot of dollars tied up in it. I don't see a real large number of rigs that’ll take place over the next couple of quarters. Brad Handler - Crédit Suisse AG, Research Division: I see, okay. So perhaps adjusting the current rate in the mid to high 50s is maybe a sustainable level for reimbursables? At least as it relates to that issue, I suppose.

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

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

Wanted to revisit a topic here on supply and demand and wondering if you could clarify your thoughts on the topic given the spike coming into the market for 2012 of about 200 rigs, about an equal number of mechanical rigs still working it. And based upon some of the previous questions on day rate levels and where you see those, I mean, to me, it looks like the supply and demand in the near term for the upcoming years is pretty well set and pricing really hasn't moved dramatically one way or another to signal and then balance. But wanted to see if you could provide some clarification there. I know you've mentioned ebbs and flows, but just basically your thoughts on how this could play out. I mean, is it possible that these mechanical rigs continue to work because of the -- they take a discount on the pricing?

Well, yes, and I'm sure you'll see them discount pricing. But I think we have enough history now to show that there'll be a group of customers that still won't find that to be an acceptable fit. And when you mentioned, Dave, the number of new builds coming in, in '12, our guess is it’ll be a little less than that but not enough to quarrel over. But when you look at a fleet the size of the U.S. land fleet and the amount of activity, that to me is not a daunting number. And like John mentioned in his comments, you had 180-plus rigs officially retired last year. And that, in my mind, is not a process that's worked itself out. That needs to continue for years and years to come where you have that amount of attrition or potentially more so. We don't see a big imbalance occurring, and we still see a very strong preference for higher-performing rigs, and the complexity of the well designs and the type of drilling is continuing to increase. And so all of those trends are favorable to our outlook and keep us from being overly concerned with the pricing dynamic.

Okay. And then a follow-up, unrelated, if I could. I was just wondering on the new builds and how much lead time you need in order to get the rigs delivered. In other words, how long is the shelf life on those 7 remaining 2012 spots? I mean, basically, when a customer comes to you and says, "I want a rig in December 2012," what's the latest date you could take that order?

Well, it's a fair question. But I guess it's a little more complicated than that behind the scenes, if you will, in terms of when we have -- we try to accommodate a customer on their preferred delivery, and so it has slots that are open in different times of the year. So maybe a general way of thinking about it is in terms of behind the scenes, our construction process is about a 6-month process. We have some slots available in the fall and then, of course, in '13. I don't know if that's given you the clarification you're asking for.

No, Hans, that's good.

We'll take our next question from Jim Crandell with Dahlman Rose. James D. Crandell - Dahlman Rose & Company, LLC, Research Division: Hans or John, you're known as having excellent relationships with the majors. And if you look at some of their build programs over the course of 2011, many have ramped up significantly over the course of the year in terms of numbers of rigs working such as BHP, Marathon, Occi, Shell, Chevron, just to name a few. And I mean, as you look at these companies' rig additions programs, without going into individual customers, but overall, the majors, do you see these companies, certain of them in the midst of major addition programs and the builds we saw these companies do over the past year could be replicated in 2012?

Well, and I'll let John add some thoughts, too. But my first thought is that like you point out, 2011 was a very strong year. We had 71 total new builds which a year ago would have been more than we would've expected. And I think it's important strategically that we got those in place, that they're fully contracted, that they’re in our queue. I think what will happen, Jim, going forward is we're hearing from customers that they have multiyear plans, and as you know, not hundreds but thousands of wells to drill. They're going to migrate to a higher concentration of tier 1 rigs over time. But practically speaking, I think as everyone transitions into the first of the year, they're kind of watching the landscape and taking an account of what's going on in the marketplace. And so in our minds, it's a timing issue and it's not disruptive for the longer term. But in the shorter term, we're probably in a transition period. James D. Crandell - Dahlman Rose & Company, LLC, Research Division: Okay. But if you -- Hans, if you look at some of these companies and if you look at a Marathon, which is going from 9 to 24 over the past year, or Shell from 14 to 25 or Chevron to 11 from 27, I mean are these the types of companies that could be at 35 to 40 rigs a year from now and they still are in the midst of a significant ramp up? After all, Exxon operates 63 rigs and Occidental is up over 50 as well.

Well, I think as you point out, when you look down our customer list, and we can't speak for our customer except to say they believe their field operations and their ability to execute and their ability to do that on scale and to have the capital structure and the personnel and the expertise and the experience to do all those things would suggest that the rig levels you talked about are not their maximum and that they're capable of doing a lot more. And I think they see it as a strategic strength. So we don't think they're done either, Jim. James D. Crandell - Dahlman Rose & Company, LLC, Research Division: Okay. And then, Hans, if you were to take that question just a little bit different direction and just look at the international companies, some of which have never really been in the U.S. market to a meaningful extent, number one, do you see some of the international companies that have just gotten in over the past year in the midst of a build? And are you having conversations with large companies that don't have any representation in the U.S. shales? And do you think we could see more new companies, meaning more international companies, entering the U.S. market as they've done in the last year or 2?

Yes, I think that's an important trend and dynamic to watch. And as you know, some of these JV relationships are occurring because these larger NOCs are coming in. And as they gain some of the operations, they will be interested in having the best available solution. And it won't just be H&P, but it’ll be a complement of the folks that -- the service providers that do it the best. And safety is a very keen requirement for them. All those things are accretive to our position. And then I think it just flows into they're over here to gain the experience because they see the international opportunities in their backyards and in other areas of interest that they have. And so I think it would be a natural continuation for that to impact our international footprint as well. So the size, the type of players, their focus on performance, efficiency, safety, all those things are positive for us and I think you'll see it making an impact.

We'll take our next question from Joe Hill with Tudor, Pickering. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: John, I think you mentioned that you were at 152 term contracts today. And if we look at kind of the progression you guys have talked about in the past, you should see about a drop of maybe 10 over the balance of the year. What do you think the odds are today that you can actually end the year at 152 or better?

The fiscal year? Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Yes, sir.

Yes, I think that's reasonable. I mean, we're giving you a snapshot of current contractual commitments. As you know, as rigs roll off of term, some roll into the spot and some roll back into another term contract. A lot of variables are involved there but I think it's -- I think 150, 152 is reasonable. I think -- we talked about 148 rigs on the last -- average of the last 3 quarters of '12 for the fiscal year. So I think that's a reasonable number. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, and then this is a little bit more nuanced. But are you seeing any change in the demand for the type of equipment? Given the change we're seeing in activity in the different basins, that is we're losing gas activity and we're picking up oil activity. And I was just wondering whether or not you're seeing more or less demand for, say, scalable equipment?

Joe, I really haven't noticed any difference. The Flex 5 has been popular, the Flex 3 has pad capability although fewer wells on the pad. And we're seeing -- as we've said before, we actually have customers going to pad drilling in areas that don't have the environmental concerns and issues like you would have somewhere in, like in Colorado. So I think it's economics-based. I think it just makes good sense to do that. But I really haven't seen it change much. I mean, we've had nice demand for that and would expect that it would continue.

And we'll take our next question from Robin Shoemaker at Citi.

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

Robin, this is Juan Pablo. One other variable, of course, that impacts the equation is the number of rigs that are currently on term that are rolling off. And during the next -- during the last 3 quarters of the fiscal year, we have approximately 43 of those that are rolling off.

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

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

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

Robin, this is John. We don't have any rigs working in the Utica today. The rigs that were would likely -- obviously, that would be most likely to move to the Utica in the future would be rigs coming out of the Marcellus that are drilling dry gas. That's always a possibility, but we don't have any in the Utica now. We do have some existing customers that are using FlexRigs in other U.S. basins that have acreage positions in the Utica. So we wouldn't be surprised to see some activity in the Utica. I don't really have a feel for when that would be. We do have rigs working in Louisiana, FlexRigs that are capable of doing work in the Tuscaloosa Shale. Again, we've got customers that have acreage positions there as well. But don't -- we aren’t, to my knowledge, we're not actually drilling any Tuscaloosa shale wells currently. I really can't think of anything that's new out there. But I think the point to keep thinking about is as rigs are redirected, use the Haynesville as an example, there's only – there’s almost 100 rigs working there, only 40 are AC drive. There's not many mechanical rigs, which you wouldn't be surprised at that. But there's close to 50 SCR, or a little over 50 SCR rigs running. Some of those rigs are probably capable of doing some of this work in the Eagle Ford or Permian, but some of them may not be. And so that's where I think we continue to see questions or decisions made by customers on whether they're going to pay to move that rig 300, 400 or 500 miles, or whether they're going to go another route with a newer rig.

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

Well, I think -- this is Hans, Robin. I think we're early on in the Utica. It's going to be a significant play. And there are others that kind of fit your headline or category, but I think the other thing to think about is as the customer focuses his technical teams and geoscience work over to oil and gas-rich liquids, you've got a lot of activity that won't be necessarily headliner status that continues to -- and I guess that's an important takeaway from this call is I can't think of a cycle where you have some uncertainty, and we've described the uncertainty. But if you have this kind of fallback of so much inventory and so much economical drilling, usually when you have price concerns, it makes everything uneconomic. Today, you have this strange delta between the natural gas prices and oil prices. But on the oil side, you've got a lot of work to be done that I think we successfully transitioned to. So that's hopefully the encouragement coming from the call.

We'll go to our next question from Jack Moore with Harpswell Capital.

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

Well, besides just some of the general things that we've talked about in terms of the type of drilling and the laterals are longer and the wells are more complex, I think one of the things that will continue to evolve is you'll shift into a more exploitation development concentration that becomes more factory-like. And that's a positive for us. So where other rigs may have been suitable to do some definition work as they go into a Phase 2 or a modality where they're really focused on their development, then I think it enhances our potential. And then I would expect you'll continue to see a trend towards pad drilling and the benefits it has in terms of environmental impact and the reduction of support services required for the same number of wells. So we're watching all of those things, and I think we're very well-positioned for that development.

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

Well, I think we've continued to develop our training capabilities. And one of the benefits as we've gotten bigger, we have the benefit of being able to seed the rigs coming online with experienced H&P folks and you have a mentoring dynamic and kind of a team-building dynamic there. And so I think we're actually in better shape today than we were in the last build cycle in '06 through '08. So there are areas where available labor is more challenging than where it might be otherwise. But even that, I think our guys do a good job of attracting, training and then retaining folks that want to be a part of the company and want to be part of the culture that we have.

Our final question is a follow-up from John Daniel with Simmons & Company. John M. Daniel - Simmons & Company International, Research Division: Sorry to be the evil sell side guy that wants to focus on quarter-over-quarter changes, but...

That doesn't make you evil, John. John M. Daniel - Simmons & Company International, Research Division: Well, just after the guy before me was pretty nice, so here I come and mess everything up. But you mentioned that roughly 43 rigs will roll off contract in the coming quarters. And I mean, I presume a number of those are in liquids-rich areas. What I'm wondering is the customers that are using these rigs now that will be rolling off contract, are they indicating a desire to re-sign those rigs? And if so, are they looking at 6-month terms? Well to well? I mean can you just frame for us that discussion?

John, the majority of those -- a large number of those 43 are more towards the back half of the fiscal year. The impression we have right now is that in most cases that we're aware of, the customer wants to keep the rig, and we would be surprised if they released the rig and there's always exceptions. But overall, we feel pretty encouraged by the level of interest. A lot of the rigs that are going to roll off are Flex 3s. And as you know, Flex 3s are in high demand regardless of the area. So we feel really good about the position. And again, many of those 40, at least we would expect, will roll back into a term contract. Again, it's going to be based on customer needs and the basin and what the demand is going to be. John M. Daniel - Simmons & Company International, Research Division: Right. But the feeling today is a good one?

Yes, I feel real confident. I feel real good about, again, about our customers and their budgets going forward. No doubt there's some concern with natural gas prices but there's a lot of plans out there that customers have for 2012 that are going to require FlexRigs to get it done. John M. Daniel - Simmons & Company International, Research Division: Okay, fair enough. And then just the last one for me. Presumably, you'll see some rigs in the dry gas market, certainly the ones that are on spot get released. Is there any noticeable difference in terms of leading-edge day rates between those rigs that are in the spot on the dry gas versus where they might migrate to?

I don't think there's a major difference, John. I mean, we'll look at that and make certain that that isn't different than that. But I think it's going to be basically the same.

There are no further questions at this time.

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

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