Helmerich & Payne, Inc. (HP) Q2 2013 Earnings Report, Transcript and Summary

Good day, and welcome to the Second 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.

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'll now turn the call over to Hans Helmerich.

Thanks, Juan Pablo. Good morning, everyone. We posted solid results for the company's second quarter, considering the sideways nature of the land drilling business since the beginning of 2013. Perhaps, some of the lack of customer urgency is fanning the ongoing macro uncertainty we all read about, including concerns around China, continuing clouds over Europe and, recently, oil prices falling below $90 per barrel. Of course, the last item, oil prices, remains the driver for the energy space and critical to our business, particularly now with nearly 95% of our fleet directed toward oil and liquids-rich drilling. Our assumption is that oil prices show resiliency in the mid-$80-plus range, which we believe would be enough to accommodate gradual growth in activity as we move through 2013. One pleasant surprise has been a nice recovery in natural gas prices as they approach the mid-$4 range with the aid of a lingering winter. While at some point, improving natural gas prices will show up in an improvement of the gas-directed rig activity, for now, better pricing helps boost our customers' cash flows and improves the economics of projects where associated gas is significant. So in a steady state market or, more likely, one with slow growth, how would we expect to fare? We have mentioned before some advantages we have in this environment. Customers are deliberate with their budget dollars and become increasingly discriminating with the service providers they engage. Even more so, as they shift into a developmental phase of their drilling projects, where consistency in performance, safety and additional efficiency capture all become imported differentiators. We would expect this to help us again to gain additional market share and appeal for first-time customers with similar aspirations. This environment also helps to moderate industry capacity additions. By our estimate, 80 to 90 AC rigs throughout the U.S. land industry are currently sidelined, and we anticipate new build additions of AC drive rigs to be around 75 or less for this calendar year. Our own plans remain unchanged, which is to take advantage of the flexibility we have in our manufacturing effort and carefully monitor new build demand as it develops for the rest of 2013. We're pleased today to announce 2 multi-year term contracts for new FlexRigs for work in the U.S. In addition, the company entered into an agreement to build our first new 3,000-horsepower AC drive rig, also under long-term contract, which is scheduled to begin operations in Colombia in the spring of 2014. We believe there is additional potential in the future for large-horsepower AC drive rigs, and we're pleased to secure this project. Since the beginning of our fiscal year in October, we have completed 20 rigs under term contracts. 8 of those have been completed since the beginning of this calendar year. Our plan for the next few months is to continue a build cadence of 2 rigs per month, in light of our expectation for improving customer demand. This is in keeping with our expectations that the oil field will see a slow improving level of rig activity during the rest of the year. Also on this call, we wanted to provide some color around the couple of issues we've been asked to comment about in the last several weeks. One is the announced decision of one of our competitors to discount spot rates in an attempt to, in essence, buy up their activity rates. While we questioned the efficacy of this strategy longer-term, we are responding to resulting market tension this has created and estimate that the impact on us will result in around 2 or 3 percentage points of downward pressure on spot rates in average during the third fiscal quarter. The market votes with its dollars, and over time, pricing tends to reflect thoughtful choices regarding performance and overall value proposition. We've shown that performance is differentiated and will be rewarded through premium margins and higher activity levels. The other issue we've been asked about deals with the difference between 2 standard options of mobilizing a rig on our pad drilling application. The main choice is between skidding the rig on a rail system or a lift-and-roll method known as a walking rig or stopper. Both systems in some form have been around since the 1970s beginning offshore. Some of our competitors have been touting their walking rigs to investors lately, and we're happy to have the discussion, which start by saying that our first experience with skid systems dates back to 1992 with conventional land rigs and, in 2004, with FlexRigs. Learning from that experience and listening to our customers' input and feedback, the skidding remains our system of choice today. Our customers helped us choose the skidding system as a more elegant design and engineering solution on our way to building over 100 pad-capable rigs over the last 8 years. Whichever mobilization method is utilized, we realized what matters to the customer is the overall well cycle performance that can be consistently achieved. To put it into perspective, the time the rig is moving on the pad represents for us considerably less than 10% of the overall cycle time. The drilling of the well and other associated activities make up more than 90% of the well cycle. So the larger issue will continue to be the overall quest for increased efficiency through the entire well cycle spud-to-spud. The fact that every one of our pad-capable rigs are AC drive helps us to safely and consistently improve performance and deliver value for our customers. We continue to get better at doing just that through a combination of our people and systems and using the best tools available. I'll now turn the call back to Juan Pablo.

Thank you, Hans. As announced earlier today, the company reported another strong quarter with over $150 million in income from continuing operations. Our balance sheet is in great shape, with a debt-to-equity ratio of approximately 6% and total assets now exceeding $6 billion. Net cash provided by operating activities totaled $494 million during the first 6 months of the fiscal year, and capital expenditures reached $438 million during the same period. We have increased our capital spending estimate for fiscal 2013 to $850 million. Approximately 60% of this total is related to our new build program, 25% to maintenance CapEx, and the remainder to tubulars and other special projects. Our depreciation estimate for the year remains at $450 million, and our general and administrative expense estimate for the year remains at $125 million. Our interest expense estimate, which is net of capitalized interest, also remains at approximately $5 million during fiscal 2013. Our tax rate for continuing operations for the first 6 months of the fiscal year was approximately 35% and is expected to remain at that level during the remaining 2 quarters of the fiscal year. The holdings in our investment portfolio remain unchanged as compared to the prior quarter and recently had a total pretax market value of approximately $450 million and an after-tax value of approximately $290 million. I'll 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. We had another strong quarter in all 3 of our operating segments, U.S. Land, Offshore and International Land. We believe our strategy of investing in our people, new technology and improved systems is paying off as the demands intensify for faster and faster well cycles in the unconventional plays. Our customers not only expect more from our FlexRigs in terms of performance, but they also expect safe, consistent and reliable operations. And our belief is better technology solutions more effectively deliver on those expectations. I'll begin the operating results discussion for the second fiscal quarter with our U.S. Land segment, where U.S. Land operating income decreased 3.6% quarter-over-quarter to $226 million, and revenue days increased 104 days to 21,847 days, representing approximately 243 average active rigs in the quarter as compared to 236 rigs active in the prior quarter. We experienced a mix of term and spot market rigs for the quarter that averaged approximately 161 rigs and approximately 82 rigs, respectively. Average rig revenue per day increased by $215 sequentially to $28,255 per day. Early termination revenue in the quarter accounted for approximately $30 per day of the increase. Average rig revenue per day for rigs working on term contracts during the first fiscal quarter was approximately 8% higher than average rig revenue per day for rigs working in the spot market. This difference is primarily attributable to the mix of FlexRig models and operating regions in these 2 categories. As expected, our U.S. Land average rig expense per day increased for the second fiscal quarter. The expense per day had a net increase of $451 per day to $13,085, with approximately $174 per day of the increase due to a bad debt reserve recorded as a result of the small customer filing for bankruptcy during the quarter. However, excluding this bad debt reserve, our expense per day would've been in line with our expectations of $12,900 per day. On the last call, I spent a significant amount of time talking about our cost management efforts, so I won't go into that in great detail on this call, but I would like to recognize the efforts of all of our people that were responsible for the great results in the second quarter. As you've heard us describe, historically, the second fiscal quarter has significant expense per day seasonality as compared to the first fiscal quarter in a range averaging $500 to $1,000 per day. And that seasonality for the second fiscal quarter of 2013 was dramatically improved. A year-over-year comparison shows our expense per day, and 2013 improved by approximately $800 per day as compared to last year's second fiscal quarter. Average margin per day decreased by $236 per day to $15,170 for the second fiscal quarter and was also negatively impacted by the bad debt expense. Hans mentioned earlier, we announced 2 new build FlexRigs with multiyear term contracts. Those new builds are designed to drill wells on multi-well pad locations. The first new build is a FlexRig3 for the Permian Basin, and the second is a FlexRig5 destined for the Niobrara in Colorado. Hans also talked about our skid system design and our customers' preference over the walking stopper-type systems. We have a current roster of 27 customers that utilize the 100-plus skid systems that are in service today, and we continue to have new customers that are adopting the use of the skid system. We have confidence the skid system delivers value and is superior to the other systems. I believe those customers know what they want and like what they're getting from H&P in terms of skid times on the pad, move times between pads and drilling performance during the remainder of the well cycle. The customers represented our large and small independents, as well as major oil companies, and continue to contract more of our skid system. Now let's shift our focus to the third quarter operational outlook for H&P's U.S. Land segment. I want to preface our outlook regarding activity and expected margins with some assumptions regarding commodity prices of the WTI being in a range of $85 and $95 per barrel and natural gas prices being above $3.50. Today, our rig count of 246 rigs continues to lead the industry rig count, an increase from 239 rigs on December 31. H&P also has captured approximately 41% market share of the AC drive rigs working today. In contrast, our 3 largest competitors combined active AC drive fleets capture approximately 39% of AC market share in the U.S. compared to H&P's 41% and make up 51% of their total working fleet as compared to 100% of H&P's. Another area we have an advantage is in term contract coverage. We currently have 161 FlexRigs under term contract and 85 operating in the spot market. Today, we have 56 idle rigs, including 21 AC drive FlexRigs. Of the 21 stacked AC rigs, approximately half of those rigs were working in the last quarter. Our rig activity has been steadily improving but at a slower rate of increase. For the third fiscal quarter, we expect revenue days to be up approximately 2% to 3% and average revenue per day to be down approximately 1%. We expect third quarter expenses to be in the $12,900-a-day range, with a range of, plus or minus, 1% to 2%. To date, we've not had -- we've not received any early termination notifications for the third fiscal quarter. Our term contract coverage for our future quarters remain strong. We currently have an average of 158 FlexRigs already under term contracts for the third fiscal quarter of '13, an average of 146 FlexRigs for the fourth quarter of fiscal '13 and an average of 110 rigs for all of fiscal 2014. Excluding costs that are passed on to customers, we now expect average rig revenue per day for our rigs on term contracts to remain relatively flat for the 2 remaining quarters of fiscal '13 and to increase by approximately $150 per day in average during fiscal '14. This is compared to the average rig revenue per day for rigs under term contract during the second 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. Now a few comments regarding the Offshore segment results for the second fiscal quarter. Our Offshore operating income decreased by approximately $1.4 million to $13.7 million as compared to the prior quarter. Revenue days increased by 2% to 720 days, as utilization remained constant at 89% for the segment. Average rig margin per day decreased by $944 sequentially to $24,838. The outlook for Offshore as of today, as the segment has 8 rigs active and 1 rig stacked, we expect 8 rigs to remain active throughout the third fiscal quarter. As compared to the prior quarter, we expect Offshore revenue days to be up approximately 1% as we continue to operate with 8 active rigs. We expect Offshore margins to be relatively flat as compared with the previous quarter. Now a review of the International Land segment, where operating income increased by approximately $4.1 million to $13.2 million. The primary factor driving the improvement was early termination revenue of $5.3 million. Revenue days decreased 10% to 2,023 days, as overall segment utilization declined from 85% to 78%. Average rig margin per day increased $2,653 to $11,053. Of the increase, approximately $2,600 per day is related to early termination revenue. The outlook for international activity has improved since our first fiscal quarter call. Today, the International Land segment has 24 of 29 rigs working, of which 15 are AC drive FlexRigs. The active rigs by country include 6 rigs in Colombia, 6 in Argentina, 5 in Equador, 3 in Bahrain and 2 in both the U.A.E. and Tunisia. We currently have a total of 5 rigs idle: 3 in Argentina, 1 in Colombia and 1 in Equador. As a result, we expect International Land revenue days to be up approximately 5%. Nonetheless [ph], excluding the effect of early termination revenue, we expect international margins to be down approximately 10% to 15% as compared to the previous quarter, primarily due to labor interruptions within our South American operations and costs associated with rigs transferring between locations to begin operations. The past 3 quarters have all experienced some choppy activity related to rigs being in transition between countries and projects, but we believe this should improve in the fourth quarter. We are pleased with the announcement of our first 3,000-horsepower AC drive rig. This rig will work in Colombia and is scheduled to be delivered in the spring of 2014, and we'll talk more about that rig in the future. In closing, we've all read multiple headlines over this past 6 months with questions regarding the impact of rig efficiency on the U.S. Land rig count, the number of wells delivered per rig, and how that will impact the rig count going forward. A lot of variables will drive the rig count. But from our perspective, those drilling contractors that can deliver the best value to their customers in terms of lower cost per foot and additional wells per year will be the contractors that grow and take market share. We continually monitor our FlexRig performance. And one of the metrics we track include the performance for the complete well cycle from spud to spud. FlexRig performance results from 2010 to year-to-date 2013 reflect the following average rig efficiency trends across all basins we work: footage per day increased in a range of 34% to 44%, while well length increased a little over 20% in an increasingly complex horizontal well environment. In addition to the footage per day improving, FlexRigs have delivered efficiencies that, on average, delivered an additional 10% to 30% more wells per year, depending upon the area. We've commented for at least the past 8 years the FlexRig is a catalyst for better performance, and customers would be willing to pay a premium for the value delivered. The FlexRig design strategy addresses all aspects of the well cycle, and we continue to innovate and improve the process. Finally, we believe our customers are demonstrating their preference with their continued support and collaboration with H&P to contract new build FlexRigs. That has enabled us to grow market share since 2006. And that completes my operating segment remarks. And now I'll turn the call back to Juan Pablo.

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

[Operator Instructions] We'll take our first question from Robin Shoemaker with Citi.

I wanted to just clarify what you were saying about the expected drop in spot pricing. So you're indicating that 1% down in the next quarter in terms of margin and then, ultimately, 2% to 3% is the deterioration you expect. So how do you kind of arrive at that number? Do you think we've -- we're bottoming out in terms of pricing pressure?

Well, let me just clarify, Rob, and this is Hans, that the 2% to 3% was addressing the spot rates. And then as you include the term coverage, which is close to 2/3, then going into the third quarter, we're looking at a 1% possible diminishment. So it's a little bit less than what you said, but just for clarity.

I see. Okay. So basically, then the 2% to 3% has already happened in terms of the spot rate, and then it's blended with the term rate. So are the idle AC drive rigs you mentioned, the 21, are they -- how -- what are the prospects for them going back to work either on a spot or term market in the current quarter?

Well, I think we're positive about it. Those rigs are all ready to work. We'd be open to either term or spot workers spread over several basins. And so it gets back to the thought that we're going to see some activity improvement and strengthening in the current quarter and then as we go through 2013, and we'd expect those rigs -- I'd like to think all those rigs go to work by the end of our fiscal year, but we'd expect to see some take up in that idle capacity.

Robin, this is John. I might also add, those 21, I commented that approximately half of those were working in the last quarter, so implied in that, some of the rigs that were stacked last quarter went back to work. So there's this kind of this churn that we've talked about. And again, our hope would be that we continue to put the rigs to work, but we have less rigs that are released. And there are just all kinds of different reasons that they get released. But our hope would be that those rigs would begin to -- or we would have fewer stacked rigs in the coming quarters.

Right. Okay. And you are negotiating, in some cases, term contracts on currently idle rigs, or would you expect them all to go to work on the spot market?

It's been a combination of both. Yes, we've had both.

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

Hans and John, I appreciate the comments on your skidding rigs, but I'm just wondering, do certain areas make it more advantageous for a skidding rig versus walking or vice versa, or is it fairly agnostic? And then as a kind of a follow-on there, are you aware of losing out on a recontracting [ph] opportunity or an opportunity, for that matter, solely on the basis that there -- it was a walking rig versus what you guys had to offer?

Go ahead.

Dave, this is John. I think the customer is agnostic. I don't think they care whether we're using a skid system or a lift-and-roll or walking or stomper system. As it relates to the new build environment, I think there's, obviously, been some traction with the walking and stomper systems with older rigs because it accommodates that older structure, and that's advantageous and will be for some -- for I think a fairly short period of time. But kind of like I said in my comments, as well as Hans did, we continue to see rigs contracted, new build rigs, for the last 5 that we've contracted were rigs that were pad drilling systems with skid applications. We continue to have a lot of demand for that. I'm not aware of a particular rig line that we've lost. I don't know the specifics there. But what I do know is that we continue to have customers pick up the systems and add systems to existing rigs.

Great. And then, Hans, just kind of an unrelated follow-on, and not that there's really any indication of change, but do you suspect looking out the way the land rig market is evolving in such a way that there's going to be more rigs in the spot market than -- versus term than there are today? In other words, do we need to get used to seeing more rigs in the spot market, or is it too early to say?

Dave, it may be too early, and a lot of that is what the market serves up. At the same time, we've got a nice profile and split between term and spot rigs. And I don't think there's a built-in bias for that moving down, meaning the term coverage moving down. The numbers we give you in terms of the 158 for the third quarter and then how that plays through, as you know, those are static numbers, so when we signed a term contract, we add that. So I don't have any reason to think that, that mix or profile would change significantly. And we just kind of see where the market takes us.

We'll take our next question from Michael LaMotte with Guggenheim securities.

First question. I don't -- John or Hans, I don't know which of you wants to address it. With...

Depends on how hard it is.

With the Saudi rig count looking to go up 30-some-odd rigs and large tenders out there, is that a market that you all would consider moving into? And frankly, looking at the tenders, are they of interest to you?

Well I'll start, and then John can add. We do have a better presence and footprint in the Middle East than we've ever had, and we've had nice performance from the FlexRigs we have there. Our difficulty in Saudi Arabia has been more contractually driven and trying to work through some of those issues and then just looking at the types of potential returns. Clearly, when they're in a up-ramp mode and adding rigs, and we've heard it expressed that they're very interested in having FlexRigs in country, so I would still like to think that we're going to have an opportunity to be over there. We don't have anything on the plate right now.

Yes, Michael, I don't have much to add other than just to echo what Hans said as far as the performance. And we have 2 FlexRigs in Abu Dhabi, as you probably know, and those rigs are really performing well, great safety performance, great rig move performance. Well cycles are much quicker than what they anticipated, and we're even doing a little bit of science work on the wells also. So I've been very pleased, and I think we've opened a lot of eyes in the Middle East. So yes, we would be hopeful that, that would happen in the future.

Okay. Hans, on the issue of cash return, I think you've been, frankly, amongst the clearest in terms of defining the spectrum of opportunities. Here's our cash flow, we'll either go to -- grow for -- or get returned. I'm wondering if in conversations that the board has had over the last couple quarters on this topic, if there's been anything you can say about whether distributions would continue to be annual or whether you would consider to move to a variable dividend structure that's biannual or even quarterly.

Yes. I appreciate the question. And we had our last dividend increase that came from our December meeting. And it's something, Michael, that the board continues to look at, and we've considered different versions of variable dividend that you're talking about. It will -- I think it's a project in progress. I think the board is very supportive and would say that there is additional headroom going forward in a dividend of some kind, and then whether or not we would move the timing of that up prior to our December meeting, I think there's a possibility of that. So all of those things are on the table and then in flux no clear direction that I can provide right now on this call, except to say that we continue to stay that carefully.

[Operator Instructions] We'll take our next question from Byron Pope with Tudor, Pickering, Holt. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Hans or John, just wanted to get your thoughts. I realized the overall U.S. Land rig count has been -- activity has been flattish year-to-date. And in thinking about your 20, 21 idle AC rigs versus the 2 rigs -- new build rigs per month that you're going to continue to build, is there any meaningful distinction between those 20, 21 idle rigs in terms of the characteristics of those rigs versus the 2 rigs per month that you're going to continue to build that, that might suggest that it might be harder to put some of those currently idle AC rigs back to work as we step through the next 2, 3 months?

I don't think that there's a stranded model out there, if you will. I think that it's a situation where we're not dissuaded or feel overwhelmed that, "Hey, we have some capacity. How does that flow back into our manufacturing plants?" And Byron, you remember, we've talked about -- as we consider our go forward on our cadence, we've had the nice situation where everything we've built to-date for a long, long time has been under contract. And when we made the announcement in the fall that we were going to go to 2 rigs in '13, starting in '13, we knew that we had a couple rigs in January, I think 1 in February went under contract. And so these most recent new build orders help us keep moving that to the right. So now we have 1 left under contract to deliver, and now here is kind of the junction we're at now, is we can take some of that equipment from the supply chain and unitize it and have it be capital spares, or it also lends itself to being new completed rigs. And so what our plans are today, to go forward for a few months, and we'll have, obviously, more information on the July call, if not before that, and we'll give a better indication of, "Okay, well, are you converting those to new rigs or are those capital spares?" but we have that type of flexibility. And based on conversations we're having with customers, I'd like to think that we're going to be able to stay with completing and putting rigs out under contract. But if it came to a point where we ended up with 1/2 dozen or a dozen-or-so rigs that we ended up building out on our own account, we'd be willing to do that as well. So part of it is a read of how we see demand developing forward and I think being somewhat optimistic about that, and that's driving our thinking and our plans right now.

We'll take our next question from Michael Cerasoli with Goldman Sachs.

This is actually Waqar Syed from Goldman. Just a couple of questions. Number one, something related to Byron's question as well. But you were the first in this sort of new design AC system rig. And as you look back at your -- some of your earlier rigs, FlexRig3s, and compare them to the FlexRigs that you're building today, the FlexRig3s, is there different equipment on that rig in terms of performance? And as you look at the performance of these rigs, do you see any material difference between the rigs built several years ago versus those being built at -- recently?

Waqar, this is John. The Flex 3s were the first AC driver rig we built, of course, in 2002. We built 32. Those 32 have continued to receive upgrades and learnings that we've had over the years that we then put into what we would call maybe the second-generation Flex 3, if you think about it in those terms. So if you look at performance in the field, there isn't a difference in the performance in the field. We've upgraded operating systems. We've added equipment that we didn't have on originally in 2002, like hydraulic catwalks as an example. We didn't have hydraulic catwalks then. We didn't have casing, running tools back in that timeframe. And like I said, we've had software improvements, and then just the monitoring that we're able to do. So the others -- there's really not any material difference in performance. But we're also, of course, building different rigs today than we did then. We didn't have Flex 5s then. We didn't have Flex 4s. And those rigs have, of course, targeted certain market segments that the Flex 3 wasn't aimed at. So -- but again, those 21 rigs that are stacked, again, another way to think about it, as I've already said, 1/2 of those worked, but they're also spread across 8 to 10 different basins. So you don't have a large -- it's not like you have a whole lot of rigs just hanging around that are waiting to go to work. There's still demand out there. We're continuing to bid those rigs. We're continuing to have interest from customers for those rigs.

Great. Another question, like if you find a need, what would it take for you to convert a normal FlexRig into like -- into a skid system rig? How much would it cost?

Well, the Flex 3s, we continue to do that. I mean, we continue to have customers asking us to add the pad system to the Flex 3s, and probably an average number is around $1 million to do that.

Okay. And is there any downtime associated with that change?

Well, there's an installation process during -- that happens on a rig move. A lot of it's done offline, but there's a 1 day or 2 day period of time that you're having to do some welding that you wouldn't want to do during the well.

Okay. So bottom line, any rig that you have right now, AC system, could be converted into a pad-type drilling rig with an investment of about $1 million and 1 day of downtime, is that fair?

The rigs that are not pad application rigs right now, which would be Flex 3. Of course, Flex 4Ss and Flex 5s are original design pad rigs. So yes, the Flex 3s can be upgraded. We're continuing to upgrade. I don't have the exact number, Waqar, but we've probably had between 15 and 20 upgraded over the last 6 months or so, I mean, something like that. So yes, it's going to -- it has continued, and I think it will continue.

Okay. Now secondly, in terms of this whole debate about a walking system versus a skidding system, let's take hypothetically that if customers start to ask for a walking system, do you have a design that you could put on a rig?

We have -- it's interesting. Again, as Hans alluded to, these systems have been in existence since the '70s. And over the years, we've made conscious decisions, and then our -- really, our customers helped us make conscious decisions in '04, and then again in 2005 and 2006, and that's why we have the systems that we have. So yes, if we had a customer that said, "Hey, we really want walking systems. It's a better application for this particular well configuration," then sure, we could do it. It's not rocket science. It's something that we can add to it. But we just really haven't had demand from our customers dip. They've been satisfied with the systems that we've had.

Okay. And the 3,000-horsepower rig that you're building for Colombia, how much more expensive would it be versus your current rigs that you're building for the U.S. market, the 1,500-horsepower rigs?

I don't know that we're prepared to talk about that right now, Waqar. I mean, it's a much larger rig, so it's going to be more expensive. It also has camp. It also has multiple tubular strings. It's not a -- you don't go out with just 5-inch string of pipe, you've got multiple tubular strings, and as well as BOPs. So it's really not a fair comparison. But what I will say is that our returns, our expectations from that perspective, it's going to be in line with what our expectations have been with FlexRigs.

We'll take our next question from Josh Lingsch with Simmons & Company. Josh C. Lingsch - Simmons & Company International, Research Division: Very helpful data points as it pertains to rig efficiency, especially as -- with respect to footage per day and wells ordered per year. I'm curious on a leading-edge basis, where we have up today, how much further do you anticipate from those moving maybe throughout -- using just year-end as a benchmark?

Josh, this is John. I want to make sure that I understand your question. So you're asking what additional efficiencies can we capture from this point to the end of the year? Josh C. Lingsch - Simmons & Company International, Research Division: Yes, yes, exactly. Just the data points you offered earlier, footage per day and...

Well, yes, it's really hard to quantify that. I mean, obviously, when you get to the point of reaching a technical limit of how fast the well can be drilled, then you're performance improvement, that's as good as it gets. But we're referencing are averages, and so I would comment that we -- I think we still have an opportunity to improve the average well cycle times closer and closer to the best in class or the technical limit. But as far as how quickly we get there, I'm not really certain. I mean, the last couple years, we've seen in a ballpark range -- and again, it's area-dependent. I'm giving an average over all of our rigs working in all the basins. Some areas, there's more low-hanging fruit than others. Some areas are -- have gotten a lot closer to technical limit. So I mean, I wouldn't be surprised if there's not another 5% to 10% that we could see this year. But again, there's a lot of factors involved in that. It's kind of a guess at this point. Josh C. Lingsch - Simmons & Company International, Research Division: Okay. And then switching gears a little bit, just a point of clarification on your guidance for International Land. The daily cash margins are expected to be down 10% to 15%. Now it's off of the adjusted cash margin rate when excluding early termination payments, right?

Right. That's correct.

We'll take our next question from Tom Curran with Wells Fargo.

Maybe a different way of approaching what I sense has been, obviously, one of the hottest topics on this call, and apologies if you've already answered either of these questions. But the first is, of the current AC drive idle rigs, what percentage of those have a skidding system?

We're looking at that -- let's see here. Well, probably, I would answer, probably 25%. I think that's probably a good -- Aaron [ph] would you agree? So that's about 25%.

Okay. And then the upfront term new build contracts you just inked for 2 rigs, which model or models are they for?

The first one we talked about's a FlexRig3, and it is going to the Permian, and it has a skid system. And the other is a FlexRig 5, which, by design, is a pad drilling rig, and it's going to Colorado, to the Niobrara.

Okay. And then in the conversations you're currently having, John, regarding the rigs on term that are scheduled to be rolling off contract over the balance of the year, in any of those cases, is the customer, in any way, hinting at potentially wanting to replace a rig that has a skidding system with one that has a walking system?

Tom, not to my knowledge. I've talked -- obviously, this has been a hot topic, and so I have talked to customers. I've talked to several customers. I've had customers in our office over the last couple of weeks, working on various things, and that's one of the questions that I've asked. And I've not had anyone say, "Oh no, you guys are missing the boat here. You need to be looking at walking systems." So I'm not aware of that. It's -- obviously, it's possible, but I'm not aware of it.

Okay, and then last one for me. Turning internationally, could you just give us an update on Argentina and the latest flow out of that market with regards to potential opportunities either to put one or more of your currently idle rigs back to work or even deploy additional, I would think, AC drive FlexRig models into that market?

Well, we have been successful in putting rigs back to work in Argentina. And we don't have contracts inked, but we feel like the 3 rigs that are stacked, we think it's possible, and those are all larger conventional rigs. We think more than likely a couple of those will go back to work. I don't know whether it will be third quarter or -- more likely it'd be fourth quarter. And -- but I think they will. We have 1 Flex 3 working in Argentina in that unconventional shale play. And I think that there's possibilities for more, but we don't have anything on the horizon right now. The rig's doing a great job. I've been very pleased. Customer has been very pleased. And again, I'm not too surprised, and they're doing a little bit of science-type work, trying to understand more about the reservoir, but I think the rig's performed very well.

And we'll take our next question from Brad Lundy with Ivory Capital.

Had a quick question. On your last call, you spoke about an increased level of focus to return capital to shareholders. Can you, I guess, provide us with a little more detail as to when the board is expected to come to a decision regarding capital deployment positions?

Well, Brad, I said earlier that the last date we took that up was in December, and we don't have a set time. We'll meet in June and then again in September. We don't have a set time of, hey, we're going to solve for this over this next meeting or the next 2 meetings. I think that the take away, though, is that we're very engaged in the topic, and I think the board is supportive. And so I think that we'll continue to put the time and effort to that issue. And so it's hard for me to tell you today what actual meeting date that will be taken up.

Got you. And in the meetings, since the December dividend increase, I guess, trying to understand why the board hasn't taken action to reevaluate the dividend and capital structure. Has that not come up, or it's focused for later in the year?

Oh no, as we've talked, it's come up, and so I don't think it's been a matter of, hey, let's take a pass on this. It's been a matter of -- we took, I think, a nice positive step in December. We have said since then that we recognize there's additional headroom and that we'll continue to move in that direction. So it's really, I think, a matter of timing and moving forward. It's not a matter of, well, we looked at this and decided not to.

Perfect. I mean, you guys have certainly done a tremendous job on the operating front over the course of the last several years. But despite that, the stock seems to have been relatively stagnant over the 1.5 years. I would certainly ascribe a material portion of that underperformance to the S&P, to the current capital structure and payout ratio. But we'd love to get your thoughts on what is the appropriate capital structure and payout ratio or what the proposals are to the board at this time.

Well, no, I know you're keen on that, and I think, for us, it's -- we have said that, certainly, we've got a great balance sheet that could take additional debt on. And we also have the nice occurrence of being able to generate significant free cash flow going forward under our modeling, and we expect to do that, and that will be solved for by returning that to shareholders in terms of the portion we're not using to continue to grow the business. So it's a nice -- I know it's not what the speed you would like, but to us, it's a nice situation of being able to continue to grow the company. At the same time, you're able to positively look at returning additional capital back to your share owners.

And we'll take our next question from Stuart Lippe with RBC Global Asset Management. Stuart Adam Lippe - RBC Global Asset Management (U.S.) Inc.: You mentioned that you said 95% of the drilling -- of your activity right now is oil drilling. Does that mean -- there must be a lot of gas being found with some of that. But I guess the question I have is, do you remember what price gas was at when you really had -- when gas, let's say, was half the drilling activity? And is it --is there a certain threshold do you think that would start stimulating a lot more gas drilling independent of the oil drilling? And that -- would that be in different fields that are currently being drilled right now?

Yes, it's a great question because I think part of the positive go forward is when customers are at a price threshold where they're willing to go back and add to their dry gas-directed rig count because, like you said, that combination of oil and liquids-rich drilling takes up 95% of what we're focused on. So that would be an incremental add to have additional dry gas-directed drilling. And so we've lived through some difficult times recently and seen gas, I think at one point, it dipped underneath the $2 threshold. So everyone was just -- a lot of gnashing of teeth. But now that we're above $4, people are starting to talk about exactly what you're asking about. We don't think it's necessarily a 2013 event, but what we would hope is that we continue to see some take-up on the demand side. And you've got this very low gas-directed count, so that's going to, I think, set up for some potential opportunities in '14 to put rigs back to work that are looking for dry gas. Stuart Adam Lippe - RBC Global Asset Management (U.S.) Inc.: Why not '13? Is that -- I mean, why wouldn't, let's say, $4.50 or $5 gas get things going this year?

Yes, well, I think there's certainly some basins and projects where the economics work at the prices we have today. Oftentimes, there's a little bit of a lag effect between you hit a certain price point and it takes some time. And I guess part of it is a sanity check of, hey, we're going to stay here for a while, or is it going to continue to move up; and then part of it is take the Haynesville. You've moved some rigs out of the Haynesville. What does it take to motivate you to go back. But that's just one example, there are other examples where it wouldn't take that much effort. But kind of the history of it has been that the industry typically goes through kind of this pause as they verify that this is a price deck that's going to stay in place for some time, and then they start going to work.

We have no further questions in queue.

All right. Well, thank you very much, everybody. Thank you for joining us. Have a good day.