Helmerich & Payne, Inc. (HP) Q1 2013 Earnings Report, Transcript and Summary

Good day, everyone, and welcome to today's first quarter earnings conference call. [Operator Instructions] Please note this call is being recorded. I would now like to turn the program over to Mr. Juan Pablo Tardio, Vice President and CFO of Helmerich & Payne. Please go ahead, sir.

Thank you, and welcome, everyone, to Helmerich & Payne's conference call and webcast corresponding to the first quarter of fiscal 2013. 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's 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. Good morning, everyone. During the first fiscal quarter of 2013, the company posted another quarter of record results in terms of net income, operating income and revenues. We are also announcing today 3 additional FlexRigs orders under multi-year term contracts. We are encouraged, after a dry spell without new orders, to see customers commit to new builds. We now have 5 contracted FlexRigs to deliver going forward with these additions. Our integrated manufacturing effort continues to offer key advantage to the company. We are coming off our strongest year in this area in terms of delivering 48 rigs on schedule and actually below budget. We've stated previously that our expectations for 2013 are to see new build demand return but develop slowly and at a substantially reduced pace from a year ago, both for us and the industry at large. Our best estimate would be that the overall industry pace of construction for the U.S. market would slow to approximately 75 AC drive rigs during calendar year 2013, delivering a total of about half of 2012's effort. That more measured rollout of new builds is a positive as it reflects where we are in the cycle and hopefully limits any exuberance for the industry to overextend. That said, we like our position in this area and we see a theme that we've repeatedly discussed continuing to play out towards a steady replacement of older, underperforming rigs. Our focus and our fleet position nicely complement the movement of customers to adopt high-performing AC drive offering. We picked up 10 first time FlexRig customers last year. In 2013, we hope to translate some current oil capacity into additional new customers as we progress forward additionally with ongoing conversations that we have related to more new build orders. We began the year for the manufacturing cadence of 2 rigs per month and will deliver on that pace through April. Additional orders would continue to shift this schedule of fully contracted rigs to the right and buy us more time in considering a limited run of rig construction on our own account to preserve a continuity of effort. Continuing to build the industry's youngest and most capable fleet not only positions us well going forward, but it also -- it allowed us to weather the turbulence we saw in the second half of last year. We are able to maintain our industry lead in terms of both activity and margins. As we look ahead, there's a growing sense from investors and industry players that the U.S. land rig count has bottomed and that the industry is poised to add an estimated 100 rigs or more during 2013. We agree conditions are improving albeit at a pace somewhat slower than we expected 60 days ago. You'll hear more on this call detailing our expectations for a flattish to slightly downward projection of revenue per day in the average rig margin per day looking forward at our second quarter numbers. The estimated reductions are small and assuming oil prices and other macro conditions cooperate, the overall direction for the year is clearly positive. You will hear additional positives in a moment from John as he describes the performance we have achieved regarding safety and cost management. Together we hope it makes the larger point that we continue to improve our organization's performance. At the same time, our customers remain deliberate with their capital spending and discriminating with the service providers they engage. In a world where the growing expectation is to drill more wells with fewer rigs and improving cycle will not treat all drilling contractors equally, there remains an opportunity to capture additional market share in an overall industry rig count that is either moderately improving, trending sideways or even potentially declining slightly. This is not a new playing field for us as we have seen all of that in the last 5 years, even as rig activity trends have been lower for the land industry as a whole, we've grown that same measure by 25%. These further growth opportunities and market share gains still allow us to give further consideration to returning cash to shareholders. In 2012, we repurchased shares and announced the significant dividend increase. Our bias is towards dividends and we will consider dividend increases as an important component of building long-term value for our shareholders. So at this time, I'd like to return the call back to Juan Pablo.

Thank you, Hans. At close to $160 million, the company reported yet another all-time record level of quarterly net income and income from continuing operations. Although we are pleased with these very strong results, we don't expect at this point to have record level earnings during the following quarter. As Hans mentioned, however, the overall direction for the year remains positive. As we continue to adjust our new build program for fiscal 2013, our total capital expenditures level for the fiscal year is now expected to reach approximately $800 million. Our depreciation estimate for the year remains at $450 million, but our general and administrative expense estimate increased to $125 million. The latter is mostly a result of increases in compensation-related expense estimates, along with growth and the number of the corresponding employees as compared to the prior year. Interest expense after capitalized interest is now expected to decrease to about $5 million during fiscal 2013, and our effective income tax rate for continuing operations during the year is now expected to be in the range of 35% to 36%. During the first quarter, we sold a small portion of the company's investment, realizing a gain of nearly $9 million. Our remaining investment portfolio now only includes shares of 2 publicly traded companies and recently had a pretax market value of approximately $500 million and an after-tax value of approximately $320 million. Assuming reasonable market conditions, it is the company's intent to monetize these remaining investments going forward. As you may recall, during the period between 2003 and 2008, we sold about 1/3 of our Atwood holdings and close to 60% of our Schlumberger holdings. 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 Hans and Juan Pablo commented, the combined results for our 3 operating segments U.S. land offshore and international land achieved record earnings during the first fiscal quarter of 2013. While I'm pleased with the financial results, it is our safety performance during calendar 2012 that I am most proud of as we achieved our best-ever safety record while adding 48 new builds to the fleet and establishing our highest rig activity in the company's 92-year history. Historically in this business, safety milestones occur during shrinking rig counts, like experienced in 2009, which create less man-hour exposure and more experienced personnel. But thanks to our employees and our customers working together, we were able to accomplish this record safety achievement during all-time high activity levels for H&P. I'll begin the operating results discussion for the first fiscal quarter with our U.S. land segment. U.S. land operating income decreased 1% quarter-over-quarter to $234 million and revenue days decreased approximately 1% to 21,743 days, representing approximately 236 average active rigs in the quarter. We experienced a mix of term and spot market rigs for the quarter that averaged approximately 158 rigs and 78 rigs, respectively. Average rig revenue per day decreased by $285 sequentially to $28,040 a day, primarily as a result of receiving less early termination revenue in the quarter. 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 spot markets. This difference is primarily attributable to the mix of FlexRig models in operating regions in these 2 categories. The average rig expense per day for the first fiscal quarter was $12,634 a day, which is $14 a day higher than the previous quarter. As mentioned previously, revenue per day was down $285 as a result of early termination revenue, and consequently, the average rig margin per day for U.S. land decreased by $299 a day sequentially to $15,406 a day. Hans mentioned earlier we announced 3 new build FlexRigs with term contracts. Two of the new builds are FlexRig5s, which are designed for pad drilling and will work in the Bakken in North Dakota. I'll give more details of the Flex 5 later in my comments. The third rig is the FlexRig4 for the Permian Basin and it's designed to replace small conventional mechanical rigs. We've continued to deliver new FlexRigs on time and under budget allowing our customers to take delivery of 14 new FlexRigs between October 1, 2012, and the end of January '13. As of today, 5 new FlexRigs with multi-year term contracts remain to be delivered during fiscal '13. Rig efficiency is the industry buzzword today because many E&P companies have figured out they can drill more wells using fewer AC drive rigs and conventional rigs. The market indicates the attention by E&P companies regarding rig efficiency improves the outlook for H&P's AC drive FlexRigs in the future. There are hundreds of old conventional mechanical and SCR rigs that are being replaced by AC drive rigs because the older rigs are unable to drill more complex unconventional wells with the efficiency that AC drive rigs can deliver. And we believe this trend will continue. Now let's shift our focus to the second quarter operational outlook for H&P's U.S. land segment, where today our rig count of 243 rigs lead the industry, an increase from 239 rigs on December 31. All 243 active rigs are AC drive rigs. We operate approximately 41% of the active AC rigs in the U.S. We have 166 FlexRigs under term contracts and 77 operating in the spot market. Today we have 53 idle rigs, including 18 AC drive FlexRigs. Even though we forecast more rigs working in the second quarter of fiscal '13, we expect revenue days to be relatively flat as compared to the prior quarter since there are fewer calendar days in the quarter. We expect average rig revenue per day in the second quarter to slightly decline by less than 1% as a result of the mix of active FlexRig models and regions of activity. Revenues from early terminations are expected to be less than $1 million in the second fiscal quarter of '13, which is in line with what we experienced in the first fiscal quarter. Let me spend a few minutes talking about our cost management efforts. For the last 18 months, we've increased our organizational focus on cost management as part of the larger effort to leverage off of our growing fleet. We are pleased with our field operations effort to improve daily operational expenses. We believe that consistency in results are achievable from a combination of our new procurement system, improved processes and the operation of a fleet of AC drive rigs designed and built by H&P. Cost pressures come from a wide variety of sources and can be influenced by a cyclical business, as well as seasonal dynamics. You may also recall from our earnings call a year ago, the second fiscal quarter historically has a seasonally adjusted expense increase, and we've seen a range from $500 up to $1,000 per day during the past 3 years. We would expect some upward seasonal pressure during the second fiscal quarter resulting in an expense per day level closer to $12,900 a day. Nevertheless, given the volatility of quarterly average rig expenses in general, it would not surprise us to see the actual results for the quarter vary in the range of plus or minus a few percentage points from the $12,900 a day target. Now an update on our term contract coverage and revenue per day forecast. We currently have 161 FlexRigs under term contracts for the second fiscal quarter of 2013, 147 FlexRigs for the third quarter of fiscal '13 and an average of 151 and 106 rigs for all of fiscal '13 and all of fiscal '14, respectively. We now expect average rig revenue per day for our Rigzone term contracts to slightly decrease by less than 1% for the remaining 9 months of fiscal '13. This decline is compared to the average rig revenue per day for rigs under term contract during the first fiscal quarter. Keep in mind that these references are only for rigs that are already under term contracts and exclude any future term contracts and any rigs that have been active or may become active in spot markets. Now a few comments regarding the offshore segment, the offshore segment results for the first fiscal quarter. Offshore operating income increased by approximately $3 million to $15 million as compared to the prior quarter. Revenue days increased by 6% to 736 days as utilization improved to 89% for the segment. Average rig margin per day increased by $2,452 a day to $25,782 due to primarily having 2 rigs previously rigging out in the prior quarter and working at their full operating rate throughout the majority of the quarter. The outlook for offshore, as of today, the offshore segment has 8 rigs active and 1 rig stacked. We expect 8 rigs to remain active during the second fiscal quarter. We expect offshore revenue days to decrease by approximately 2% and margin per day to be down approximately 5% in the second fiscal quarter of '13. Now shifting to the results for our international land segment where operating income increased by approximately $2 million to $9.1 million. The primary factors driving the improvement were increased activity and margins. Revenue days increased 12% to 2,237 days as overall segment utilization improved from 79% to 85%. The average rig margin per day increased $190 to $8,400 a day as the expected negative effect of downtime and labor interruptions in Argentina were offset by improving margins and other international operations. The outlook for international has been slowed a bit by year-end seasonality and transition of a few rigs. Four previously active rigs have become idled during the last several weeks. Today the international land segment has 22 rigs working, of which 14 are AC drive FlexRigs. Included in those active rigs are 5 rigs in Colombia, 5 in Argentina, 5 in Ecuador, 3 in Bahrain and 2 in both UAE and Tunisia. We have a total of 7 rigs idle, 4 in Argentina, 2 in Colombia and 1 in Bahrain. We expect 1 of the 2 stacked rigs in Colombia will return to work soon and the other rig will transfer to Ecuador. In addition, 1 of the 4 idle rigs in Argentina will soon resume operations. As a result of this rig transition, we expect international land revenue days to decrease by approximately 10% and the average rig margin per day to be down 10% to 15% in the second fiscal quarter of 2013. In closing, I have a few remarks about why we believe H&P has a great opportunity to continue to take market share in U.S. land and international markets as unconventional resource plays and a higher percentage of horizontal wells are drilled. Since rig efficiency commands the headlines, let me review some of our FlexRig technologies and accumulated learnings that have contributed to our performance lead. AC drive technology has been a game changer for drilling rig efficiency during the unconventional resource expansion. H&P's FlexRig3 AC drive technology was introduced in 2002, creating a first-mover advantage. Since then, we have accumulated over 1,000 rig years of drilling experience with this advanced technology. A contractor would need to order 100 AC rigs for 10 years to achieve an equivalent experience base. Even if the AC drive rig experience of all other land contractors is combined, we don't think that it would match our continuity of effort. H&P's AC drive experience and learnings are a significant competitive advantage in delivering efficiency gains. For example, we drilled over 53 million feet of hole in 2012 and we improved our footage per day by 23% year-over-year from 2011 to 2012. H&P's also led the industry in pad drilling technology. In 2006, we designed a multi-well pad drilling application and deployed the FlexRig4s, which was specifically designed for movement over wellheads in the X and Y directions. Some in the industry described us as a bidirectional skid system. Further engineering development in 2011 created the latest generation pad rig, the FlexRig5, also providing movement over wellheads and in the X and Y directions, with even longer extended reach capability and horsepower. We've drilled over 5,000 wells on approximately 1,000 pads to date with our pad drilling systems. We believe these and other innovation efforts will continue to position H&P to take market share from conventional SCR and mechanical rigs as E&P companies move from exploration of unconventional resource plays to a more mature development mode of the reservoir. That completes my operating segment remarks. And now I'll turn the call back to Juan Pablo.

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

[Operator Instructions] We'll take our first question from Kurt Hallead with RBC Capital Markets.

So we've heard now from Schlumberger and Halliburton among others an expectation that the U.S. rig count will increase now about 100 to 150 between low point December to the end of March. I guess, I'm trying to gauge of that 100 to 150, what do you think the market opportunity is for Helmerich & Payne?

Well, Kurt, I'll take a stab at that. This is Hans, and then John can jump in as well. It's hard to predict where that goes. I mentioned that things have started out in January a little bit slower than we thought they might have back in late November or early December. But we still believe those plans are intact and we'll still see some increases rollout. But as you know, from watching this business, it's hard to -- we're either going to be wrong on the upside or we're going to underestimate it. I think the point that I'll make, and then let John add is we're not strapped to this overall rig count as a determining factor of how we do. I think we're going to be able, in a subset of whatever the macro rig count does, continue to gain market share. I believe that as customers bring rigs back on, their strong bias is going to be to bring AC drive rigs on for the better performance. So we would hope that it would prove out to be that we disproportionately gained by an improving rig count.

Kurt, this is John. I might add that, so far year-to-date, it's been a little -- the activity has been a little more sluggish than probably what we expected back in -- back towards the end of 2012. I mean, we've obviously picked up our rig count. But it seems like it's gone a little slower than, at least, what we expected. And it seems to me if you said by the end of March, I think 100 rigs would be pretty difficult to see by the end of March. I think it's possible through midyear. I think the other thing to keep in mind is the rigs that -- consider what rigs are going to go back to work. If you talk about 100 rigs, you've got approximately 70 that are AC drive rigs. You would think those rigs would be the most likely candidates to go back to work first. And then at the same time, we also have new build AC rigs that are being delivered, I don't know exactly at what count. As Hans mentioned that an estimation would be 75 for the year. So maybe there's 30 of them, 35 for the first half of the year. So there's your 100 rigs, assuming that that's going to happen.

Okay, that's helpful. The follow-up to -- follow-up I have is when you indicated here your average revenue per day progression being down 1% for the remaining 9 months of 2013 relative to, I guess, where you exited December, that excludes any near-term or idle rigs going back to work. So from that standpoint, based on what you know today, as those new rigs come in and are contracted and the idle rigs go back to work, is there a risk that, that down 1% becomes like a down 3% or down 4%?

Well, Kurt, first of all, I think the 1% for the rest of the year was directed to the term rig portion of the fleet. So what we know is we look closely at that. Those rigs under term have that type of small 1% diminishment. Then stepping back, the other part of it is the mix. The Flex 4s are going to command slightly less than the 3s and 5s. So I think it's a combination of that term and mix that led us to that prediction.

But I guess and look, I think that part of what you guys indicated today about your relentless focus on cost control that, that's only half the equation, right? The other half we really got to focus on is cost and what we really need to focus on is margin per day, right? So maybe in that context on the margin per day basis, what's your perspective as the year progresses?

Well, Kurt, I -- again, on the term rate being down, again, it's a function of the mix of the types of rigs. We haven't seen, up to this point, any degradation in our pricing on Flex 3s based on what we've seen. So yes, it is -- I mean, it's possible there's always pricing pressure out there, even in strong markets, there's pricing pressure out there. Our position is pricing is going to be a function of performance. And obviously, we think we're doing a lot of things well in the performance side and we think we're going to continue to get better. And so I think that's what it's going to be a function of. You say if we bring in the 18 rigs that we have stacked today as an example. I think we could probably put those rigs to work at some deep discounted day rate. But we choose not to do that. We prefer to work the rigs at what we think is a price that makes sense in the marketplace.

If I could just finish up by saying you also indicated that you have your Flex 4s going into the Permian and essentially replacing conventional mechanical rigs. How does someone like myself assess that trend? It probably is accelerating, but where are we on that slope? How fast can those Flex 4s potentially displace mechanical rigs in a basin like the Permian? Is there -- aren't there a number of E&P companies that still operate in the Permian that no matter how you try to pitch their efficiency, we've heard them say, "Well, it all depends on the crew. It's not the rig and we're happy with the mechanical rigs." So how does someone from the outside try to assess that?

I think it's been a steady march and we've heard exactly what you've said for a long time and the notion was that the Permian was an area where that was going to be the last stand for the lower performing rigs. But in fact, you've seen us continue to ramp our AC drive rig count there. So it's hard to give you a sense of speed, but we've just seen a steady shift over to -- and part of that shift coming over to AC has been that the well complexity in the Permian continues to increase and the well design lends itself better to our type of rig offering.

We'll next go to Jim Crandell with Dahlman Rose. James D. Crandell - Dahlman Rose & Company, LLC, Research Division: Juan Pablo, how much -- how many in your $800 million capital budget -- how much -- how many new builds does that include?

That includes 19 committed new builds to be delivered during the fiscal year, Jim. The new build, if I may add to that, the $800 million includes about -- between 50% and 60%, probably close to 55%, of that includes funds for our new build program, and that includes the 19 rigs that I mentioned. And also other funds for spare capitals to allow us to be well prepared to respond to additional demand and to have spare capital or capital spares for our existing fleet. James D. Crandell - Dahlman Rose & Company, LLC, Research Division: And when you talk about limited new construction for your own account without a contract, to what magnitude would you be willing to do this in 2013?

Well, Jim, this as Hans. You've heard me say and we've talked about particularly coming off of -- I think this is the first new order we've had since late spring of last year. And as we manage going forward, we're hoping, and I want to stay with a business model that has everything that we've built, which has been the case, be under term contract. At the same time, as we look forward and try to make plans and try to have the supply chain ready to respond, we've thought, well, if you have a period where you're no longer beating that cadence, would you be willing to bridge it, if you will, with some rigs that you'd build on your own account at a much reduced cadence. And I think, again, not our preference, but if we are asked, would you, in fact, do that? Yes, we would probably do that, but I believe we're talking about a handful of rigs, half a dozen, dozen rigs. And what I would expect to happen is that we would see customers stand -- step up and all of those rigs would actually be spoken for. But that gives you a sense of scale of what we're thinking. James D. Crandell - Dahlman Rose & Company, LLC, Research Division: Okay. And to what extent then -- maybe John this is for you, but if you look at Helmerich & Payne's market share position in AC drive rigs today, it's overall very strong, but it does vary significantly by region where you've had dominant positions in the Eagle Ford, very strong in the Bakken and some of the historical plays. But let's say, the Haynesville and the Marcellus, to name 2 relatively second-tier market shares, to the extent we see a strong gas-driven recovery and let's just say, the Haynesville and Marcellus are leading the way on the upside, to what extent do you expect Helmerich & Payne to build up to get to, let's just say, with the normal market share? Or do you think the company can be a leader in those markets, or is the company just sort of too far back in those markets right now.

Well, Jim, the Haynesville we were -- at least at one point in time, we had 30 rigs, 28, 30 rigs working in the Haynesville. So we've been there and we didn't move the rigs out. Our customers actually moved those rigs and they transitioned them really pretty early in the cycle. Those rigs were mobilized to the Eagle Ford and the Permian and the Woodford pretty quickly when gas prices began to slow down. So I would expect a similar type ramp. And we've been -- we've had large market share in both East Texas and Louisiana over the years, and it's been in line, if not higher, than our average market share. So that's a really strong area for us, and we have a lot of experience. The Marcellus, on the other hand, we were slow to go in and it was purposefully slow. The margins in the Marcellus for drilling contractors have been on the low end of the spectrum. If you look at the activity set in the Marcellus, it's been heavily dominated by older, mechanical rigs. And quite frankly, a lot of our longer-term customers haven't had a lot of acreage up there. And I think the other thing is when there were the opportunities to get up there, in a lot of cases, you had to mobilize -- you had to take on a large portion, if not all, the mobilization of the contractor to get the rigs up there, and we just didn't see that it made any sense. But I am seeing traction. We have, remember, I think, maybe in the Utica today, we're 4, 5 rigs. We've got a handful of rigs in the Marcellus. We continue to see some interest from customers for the Marcellus. So I sure wouldn't rule that out. I think, and again, we've got a great rig and a great brand, and I think we're going to have the opportunity to grow in any of these basins. I think customers will sponsor us. James D. Crandell - Dahlman Rose & Company, LLC, Research Division: Okay. And one last quick one. Hans, do you see the international opportunities for Helmerich & Payne now as, let's say, better than they were 1 year ago or 2 years ago? And I mean, is the outlook, let's say, for the desire for new AC drive rigs improving in enough markets where you really see things sort of crystallizing internationally over the next year or 2?

You're right in the way you frame it up. But it kind of depends on when you ask us how we feel about it. I think as you know, we've been patient in regard to that market and we really want to see it be kind of a demand pull. We've got a great customer roster that's capable of sponsoring us in international markets. I'm still overall bullish and think that you'll see some traction of unconventional shales being pursued in international markets. But as you know, watching this thing, the last 3 or 4 years have been disappointing in that regard. Does '13 look better? Yes. I think today, we would say that we're a little bit more upbeat about it and we are having more customer inquiries. All the while in the last couple of 3 years, we've increased the number of FlexRigs that we've put into those markets. And it's been slow but we would like to see that increase. And so I guess the reason I'm being hesitant is because it just takes longer to develop and you just have to have a lot of patience. I do think that we're very capable of being in selected markets over there. We're going to be very return focused. And I'd like to think that when we're talking over the next year, you'll see some improvement there.

We'll move now to Robin Shoemaker with Citi.

You gave some good explanation in the quarter. But there's just a couple of questions I had. I had noted that you had expected a significant increase in rig operating costs in the first fiscal quarter up to about $13,200, and instead it was about $600 lower, basically flat with the prior quarter. So what changed there?

Well, Robin, this is John. Yes, I tried to describe that in my comments. Our experience has been we see a lot of volatility quarter-to-quarter. And we had a good, not great -- we had a good third quarter on expenses, very good at $12,600 in the fourth quarter. And just again it was -- our expectation was, is that more than likely that the expenses were going to be higher. But as we work with our new systems, our new procurement system, other systems we're working on, the other variable that's changed over the last 6 to 9 months is that we're operating 100% AC FlexRigs today. That has an impact. And so what we're trying to address is if you look at a historical basis, there's a lot of volatility quarter-to-quarter. There's a lot of things that drive volatility as it relates to the cyclicality of our business; our rigs going up, our rigs going down, are you moving them from basin to basin, and then -- so then the seasonal aspects that we have, which we talked about for the second fiscal quarter. So I think we're getting better. I think we're getting better all the time. The best -- our best guess at the time, our best estimate was what you -- what we guided to on the $13,200. So...

Okay, understood. Similarly, you had anticipated an average rate margin in international to be down 10% in the quarter the first quarter and it was up slightly. So now you're saying the rig margin will be down 10% sequentially in the second. Is this fluctuation principally around utilization? You had really good, clearly, utilization and it seems like it's going to still be pretty good in the second quarter.

Well, the first quarter, we had -- and we talked about this on the fourth quarter conference call. We had some downtime and some labor union issues in Argentina that we thought -- well, and it did affect the quarter. But because we had some other rigs and other countries actually performed better than expected, it outweighed that. So we did, in fact, have the labor issues. We did, in fact, have some rig downtime, but we did better than expected in other countries.

Okay. And is the -- is there -- are the labor issues in Argentina resolved? Do you anticipate -- is that part of what drives the down 10% margin in the current quarter?

Well, the current quarter is -- again, we've gone from 26 rigs, operating to 22 rigs. We've got a couple of rigs that are going back to work, the other rigs, I think, eventually will, but they're not going to impact this quarter. The labor union challenges have been there for several years in this one particular area that we're working. And to my knowledge, we're not having that in this particular quarter. But that doesn't mean that it couldn't happen. So what's driving the margin down is the activity that we're seeing. And we also have transition of rigs. In one case, we're moving a rig from Colombia to Ecuador. We'll -- we think we'll have a contract for that rig in Ecuador, but it won't impact this particular quarter. So just a lot of transition between countries and rigs being down and going back to work.

We'll go now to Brad Handler with Jefferies. Brad Handler - Jefferies & Company, Inc., Research Division: I guess, I'd like to come back on what a couple of my peers have been asking you about and just maybe position the questions a little differently. If -- maybe, first on the costs. We sensed from your comments in the last call that maybe $13,200 was a sort of a good reference point, allowing for the volatility that can happen. And I guess I'm wondering if given your comments -- given your performance in the December quarter and given your comments about the March quarter, is your confidence building at all that, that number may be sustainably lower? Do we see some signs of that perhaps?

Well, again, part of the challenge in the second quarter, as we said, is this quarter always has a seasonal increase. And our experience the last 3 years has been a range of $500 to $1,000 a day. So our thinking is, okay, we're working this hard, we're getting better, but we still expect there's going to be some seasonality. And then there's -- when you're working 240 to 250 rigs and working in a lot of different basins, obviously, there's a lot of variability. We'll stack probably 10 rigs in this quarter. We'll reactivate 10 rigs in this quarter or how many rigs, maybe 5 or 6 rigs. So with that, you've got some variability. Again, we think we're getting better so that's the reason why we're guiding at 12,900. But also want to make certain everybody understands that there can be some additional variability and we think it's in a 1% to 2% range, up or down. Brad Handler - Jefferies & Company, Inc., Research Division: Sure. I appreciate that. But I think you've just amplified on it. I think it does sound like your confidence is growing. So it sounds like you're saying, "Yes, we are sustainably better." which is great.

Yes. Brad, this is Hans. I appreciate the interest and maybe frustration on the listeners end of this, because what we're trying to do is give you the best visibility we can. And I think the take away is what you just said, we're getting better with systems and processes. We've got a great focus on this. We see it not just quarter-to-quarter being important, we see it long term being a strategic advantage and being important to us. So I think we are getting better. And so what we're trying to balance that with is what John just said, some of the complexities and the moving parts around the 240 rigs and the different things that we know push that pressure upwards. So understand we're trying to just give you the best visibility on it we can. Brad Handler - Jefferies & Company, Inc., Research Division: Sure, understand. Let me turn back to an earlier line of questioning. And Hans, you had some interesting commentary about, I think, about the spot -- effectively the spot market and opportunities to put rigs back but at a rate that's unattractive. Can I ask it more sort of directly about the spot market today in AC rigs and maybe in a couple of different basins and what you are seeing there?

I'll let John kind of tell you what we're seeing in terms of basin specific.

Brad, I touched on a little bit. We're seeing our spot market pricing for the various rig models, FlexRig models, FlexRig 3s, 4s and we don't -- of course, you know we don't have 5s in the spot market, but that pricing has held up well. We had some softness if you recall back in probably August, September. And since then, I think we've been able to establish a spot market price. We've seen some pretty good strength in the Permian, and we've seen some nice strength in the Anadarko Basin. We've moved rigs out of Eagle Ford and out of Permian into the Anadarko Basin. Obviously, we've seen some additional interest in the Bakken. We have the new builds that are going there, but we've also moved some rigs out of Colorado into the Bakken. So overall, I think we've been very pleased with the pricing that we've received. We've also entered into some additional term contracts for existing rigs. And again, that was part of the mix that we talked about that kind of lowers the overall average term that we had expected in the last quarter. So overall, I think we feel pretty good. It's normal-type negotiations and we're seeing the rig -- our rig count continue to increase although not -- maybe not as quickly as we had hoped. Brad Handler - Jefferies & Company, Inc., Research Division: Okay. So with 70 idle AC rigs, and I know this is -- you're going to feel like this is unfair because it's not differentiating H&P in the negotiations, but with -- I guess what I hear you saying is that that's not -- that number, which is a decent-sized number, isn't weighing down on that negotiation or at least not very much? And is that -- do you have a sense as to why that is? Is that surprising to you?

Well, I think one way to think about it is AC rig utilization in the U.S. is around 86%, 87%. And I think our experience would tell you that when our utilization is up over 80%, typically pretty strong pricing or at least stable pricing. And then -- so that's one slice of it. And then think about it, you've taken 70 rigs and spreading it over 8 or 10 different pretty active basins. It doesn't end up being a lot of rigs that are out there available that are competing. And again, I mentioned earlier that pricing -- we believe pricing is heavily weighted towards a function of drilling performance. And customers are willing to pay for that because of what they get from it. And so I think in some cases, we'll see competitors that are pricing AC rigs at what we hear at least are pretty low numbers. And I think it has to be a reflection of the performance that those rigs -- those particular rigs are having in those basins. To me, that's the only thing that really makes sense why the pricing would be at that level, if, in fact, it is at that level.

We'll go next to Dave Wilson with Howard Weil.

Hans, just real quickly. Given your comments regarding that the rate of rig ads to the industry which at least from an outside perspective seems to suggest a fairly balanced market. What do you think ultimately that portends for day rates? Are we on the fence as an industry in terms of day rates going higher or lower? And given John's comments on pricing for performance, is there much more there for H&P to push prices higher?

We were just talking about 70 AC rigs being available, and then if you go back to what I said, we've got some 75 new builds come on. So that matches up pretty nicely to what people are suggesting might happen at least through most of the year in terms of rig ads. So it would suggest that maybe we're at an equilibrium on price. I mean, our experience is it never quite goes that smoothly. And if the oil price stays up and folks start ramping up a little bit more, not all of those 70 AC rigs are created equal. I think there's a preference towards the better performing ones. And I think in that type of demand scenario, there would still be some upward opportunity on pricing as we go through the year. But at the same time, I wouldn't think it would be -- I don't think it's going to be real aggressive. Then I think the other thing to consider is when we talk about additional new builds, those prices aren't coming down, those prices are going up. And if we're pricing correctly and our peers are pricing correctly, that should push those associated day rates up as we -- as an industry introduce more new builds. So all in all, I wouldn't think there's a lid on pricing where we sit today. And I think if things go as we hope they do, you'd see some opportunities for increases.

Great. And then one final one. What are the possibilities of retiring your remaining SCR rigs this year? I'd imagine the cost associated with those rigs being on the sidelines is pretty low. But just wanted to get a sense on how you look at the demand for those rigs over the coming years.

Well, our sense is the quality of our SCR rigs is very good. And again, part of it is a bet on the industry improving more than we might think it will. And in that case, some of those rigs may be engaged. I think there are also some opportunities internationally for those rigs. We would consider that at the right pricing and right terms. And then as you know, we've disposed and sold some of those rigs, and so there may be interest in a market out there for that. So there are several considerations and we hope that goes well.

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

So picking up on the line of questions around daily OpEx. On a same-store sales basis, so looking at a constant mix within the rig fleet, if you were to go across the major components of daily OpEx, where are you -- where do you expect to continue to see inflationary pressure and why? Where is it leveling off? And where do you expect it to start trending down?

Tom, this is John. First of all, I don't -- I wouldn't consider inflationary costs. I don't think that there's necessarily an inflationary cost. I think one of the things to think about -- and I said, we made over 53 million foot hole last year, and it's a function of activity and drilling wells. And again, I think creating an organization that can manage -- that can manage that effort and manage the costs like we're trying to do. I mean, there's really nothing that I can think about -- maybe, I think, labor cost should be relatively flat. I don't see an increase in labor. I just can't think of anything in particular that we're concerned about that's different than normal. I mean, we're always concerned about how our costs are trending and things that we're working on. But nothing really comes to mind. Again, the power of having a fleet that we've built, that we've organically grown, I think, gives us an advantage in our maintenance and cost. And then just working these rigs for many, many years and having a team of people that know what to do, then, again, that's what we're hanging our hat on, is that we're going to continue to be able to prove -- improve on that. I know it's not a -- there's really no straightforward easy answer that says, "Yes, this is where we're concerned about."

One thing, John, you mentioned, I think, earlier is it's really hard to predict the rotation. So we think the trend is upward this year but embedded in that will continue to be rig rotation and customers coming on. Some customers, we mentioned haven't -- 10 new customers, well, we had 50% more new customers in that, but it blends out or nets out to be 10. So you still have that, Tom, to contend with, tough to predict that.

Sure. I guess, honing on in the labor market, what I had heard and it was a industry-wide comment and given all of your stats when it comes to your workforce, it may not apply to you at all, but that -- within the labor market, you were beginning to see an ease in the competition for the entry-level positions like a floorhand, a roughneck, but the market was remaining tight for the more experienced skilled positions, such as rig manager or toolpusher. And didn't know if that applied for you as well. It doesn't sound like it does, though.

Well, I will say that we talked about our safety record, had our best safety record ever in a year that we've put 48 rigs out, new rigs, and had our highest activity level. We're able to do that because we have great people, we have great leadership on our rigs. And so I don't want to say that labor isn't a challenge. I mean, labor is always a challenge regardless of the industry that you're in. Our top guys, our rig managers and drillers and derrick hands and superintendents, I mean, we just have top-notch people. And I think a credit to the company, we have a great rig fleet and a great place to work, so we've got an environment that attracts people. I can't -- I don't know how that compares to our competition, but we see a lot of guys that are working for H&P that used to work for brand X. And so I think we're in a really good position. I think we'll continue to attract some of the best people. And I think we're in a very good position.

Sure. And your historical average 10 years by position, retention rates and internal promotion rates would all support that. Moving on, based on some other conversation I've had, there's seems to be an emerging consensus that the pad drilling market could expand until it's as much as 1/3 of the active rig count. And in this case, I'm just defining pad drilling in the broadest sense, meaning, any drilling that involves some form of moving technology from bidirectional system to a walking beam. What is H&P's view on how large that market can become? And where should they make inroads? In other words, which are the specific basins where pad drilling just makes little to no economic and/or scientific sense?

Well, we've talked about this for several years. I think we probably talked about it first in the Eagle Ford. Previously, and you go back to 2006, the pad drilling that we did in '06, it was a function of environmental and building fewer locations in mountainous locations and areas like the -- in Colorado or in areas -- in rural areas or areas where you've got cities and you want to build fewer locations. But a couple of years ago, we saw real quickly that the Eagle Ford was going to go to pad drilling very, very quickly. I don't know that it's an uneconomic solution anywhere. I think the one thing to think about from an operational perspective is that because you're drilling horizontal wells, you've got a directional component. And so it's really -- the best thing to do is to build a pad, and whether its 3 wells or 5 wells, you can limit your expense on the well construction, you limit your expense on trucks, moving rigs from one pad to the next, if you're drilling single-well pads. So I think it makes all the sense in the world. I don't really have a feel for whether it's a third or whether it's a half or 25%. I really don't know. But I think, it is going to continue to gain traction, particularly as we drill or as our customers drill less exploratory work and they begin to develop the resource. We talked about that in our comments. I think that will also enhance the likelihood of more pad drilling.

Okay. Last one for me. In Argentina, YPF has this shale development blueprint to invest, okay? I think, it's $30 billion over the next 5 years. But it's hinging in part on the recruitment of strategic partners to provide the technical know-how and funding assistance. Now that they've nearly finalized 2 such deals, 1 with Chevron and the other with Brittas [ph], and seem optimistic about securing other partners over the next few months here. Could you give us an update on your strategic thinking about and expectations for Argentina? What would it take for you to mobilize additional rigs into that country?

Well, I think it's a great market. You've done a good job of kind of describing the update. I think, for us, it's what we've said before. It's going to be an acceptable contract with a customer, a good customer. And we have that just today with one FlexRig operating an unconventional play down there. And we would hope to see more of that. We've got a great group down there, great set of people that can support a larger operation and we hope that, that happens. As you know, Argentina hasn't always made steady progress forward, but this is a great opportunity for that country. And if we have the right contract with the right customer, we'd like to participate on a larger scale.

So stay tuned, I suppose?

Yes, that's right.

We'll move now to Waqar Syed with Goldman Sachs.

My question relates to your expectations for rig count increases. Which basins do you see the rig count to go up the most in the coming months and quarters?

Waqar, it's John. I think probably the Permian. The Anadarko Basin, I think, has still some upside for us. Obviously, we talked about the Bakken, the new builds going there. And there's a couple of rigs stacked, I believe, in the Bakken that we have an opportunity to put back to work. So I would think those are probably the most likely areas. We see a little -- it doesn't amount to much, but it's a little bit of growth in the Niobrara. We have some great customers in the Niobrara that have very good acreage positions that are doing a great job. And so that's got a little bit of growth potential.

Great. And then of your stock portfolio, how many shares are now remaining for Schlumberger and Atwood? Is it the same number as the last quarter...

It is. It is. 8 million in Atwood and 967,500 in Schlumberger.

We'll move now to John Daniel with Simmons & Company. John M. Daniel - Simmons & Company International, Research Division: Juan Pablo, with CapEx winding down this year, how do you see cash taxes and just the deferred tax liability by now or the next year or 2?

We expect to continue to defer income taxes not in -- not as much as we did in prior years. I think during the last webcast, we estimated that we might defer approximately $40 million of income taxes. Given the extension of the bonus, we expect that to grow. It will depend, of course, on many moving variables. But we wouldn't be surprised to see that at over $75 million. In other words, the $40 million that I mentioned before will be over $75 million at this point. And in coming years, it will, of course, be a function of what CapEx levels we may have at that point. John M. Daniel - Simmons & Company International, Research Division: Okay. So just for a non-tax guru, your deferred taxes were, call it, almost $200 million in fiscal '12. You're seeing $75 million for this fiscal year?

Correct. John M. Daniel - Simmons & Company International, Research Division: All right. And then, in the course of trying to take copious notes I missed some of the commentary on the sale of securities. Could you quantify or put the timing of the sales of Atwood and Schlumberger? And did you say 100% would be sold?

No. No, we mentioned that we had sold some holdings that now leave us just with those 2 equities, and we referenced having made some sales prior to the big '09 downturn. And I think the takeaway is that both of those stocks in our mind have more running room, but they're clearly kind of back in a fair way that they were when we were monetizing holdings there and that we would continue to do that. So we really don't have a set time or price point or that type of specificity. It's really more just to say we would have a plan to see the opportunity to monetize those going forward. John M. Daniel - Simmons & Company International, Research Division: Okay. Finally, I guess, another way of asking it. Is there a plan in place right now over the course of the rest of this year to monetize that?

See, that's what we're trying not to... John M. Daniel - Simmons & Company International, Research Division: Okay. Fair enough. I'll now move on. On -- I've just got 2 more here. International, how often are you guys participating in tenders versus direct negotiations?

John, this is John Lindsay. We have -- we participate in a lot of tenders, but our success, both in the U.S. and international, is typically negotiated internationally. And you've heard us talked about this before, internationally in a lot of these countries, particularly if it's NOC, I mean, by law, they've got to go with low bid. That pretty well disqualifies us. So that -- we have to have customers that are willing to sponsor. And I think one of the things that Hans touched on earlier, one of the things we're excited about is we're seeing more interest in customers talking to us about getting FlexRigs internationally. John M. Daniel - Simmons & Company International, Research Division: Fair enough. I'm just trying to get the sense -- I mean, I understand how these guys have to get low bid, that's fine. But when they go low bid versus what you're quoting, what's the typical differential?

I don't really have a feel for it, John. What I would say is we're beginning to sense -- see NOCs that understand the difference and understand the advantage and they're trying to figure out ways to make it work. And so that's one of the things that were encouraged by, but I really don't have a feel for what the difference is. I mean, there's just so many different variables depending on the contractors in the country and -- versus -- is it local content versus other contractors. John M. Daniel - Simmons & Company International, Research Division: Right. Last one on this topic, then I'll move to my final question. But on the tenders, you find that the people that are winning these things on the low bid, are they fellow North American players or are they other international land drillers, Deutag and so forth of the world? Who tends to win these things more frequently in the last couple of quarters?

I just really don't have a feel for -- a lot of times we see these tenders, but we don't ever see the results. Generally, when you hear about the results, it's a couple of years later when someone reports how much money they lost on that tender 2 years ago. John M. Daniel - Simmons & Company International, Research Division: Fair enough. Okay, I've got last one just to play devil's advocate and I hope this doesn't offend anyone there. But you noted that some competitors are pricing lower on some AC rigs which might be reflective of their performance. Under that logic, you guys have 18 AC rigs idle right now, if performance is better, why shouldn't we see those rigs go back to work if the NTs are going to continue to sponsor new builds?

I think you will. I think our sense is that those rigs would kind of be the first off the shelf. And so part of it is they're spread out in kind of 2s and 3s on several different basins and part of it is just where the pickup occurs and what the timing of that is. John M. Daniel - Simmons & Company International, Research Division: Okay. So we shouldn't see that -- those 18 as any type of reflection of your performance on those rigs.

No. And I also would say that they are -- I think their profile or performance capability matches what you'd expect from a flex rate.

John, one other thing to keep in mind. Last call, I think we had 20 AC rigs stacked. Well, the 20 then and the 18 now are a different set -- I mean, these rigs are transitioning. You get a rig released and it'll stack, and then you have another one that's been stacked for 1 month that goes back to work. So there -- and you have -- in those 18 rigs, you have 4 different -- 3 or 4 different models of rigs spread out like we said over 7 or 8 basins. So it's -- yes, there's just a lot of transition and a lot of moving parts on the rig. John M. Daniel - Simmons & Company International, Research Division: Okay. Can I just please have one more in if there's time? Real quick. Let's hypothetically say you divested and you got out of equity portfolio, what would the use of proceeds be for?

Well, we'd love to see the rig demand jump up and we just start building them faster again. But I think I mentioned in my comments, we expect to generate some free cash going forward and we're not sure exactly the timing or the amount, but we think a big part of that's going to be returning some of that to shareholders so it would fall into that potential bucket as well. I know we're going a little late. We're happy to answer more questions. We're eating into your guys lunch hour. We still have 45 more minutes before we eat. But I don't know if. . .

We have a question from Michael LaMotte with Guggenheim.

I wanted to follow-up on your comment concerning your preference for dividends. If I look at the big jump this year, it really only added $30 million or so call on cash. And I'm looking at free cash flow at kind of $100 million to $300 million probably over the next few years. I'm wondering if you would consider a variable dividend model for this period of very strong cash flow for you.

Yes. And it's going to be -- I'm going to be cautious in how much I say or how many specifics we give. But I would tell you that the board is very much engaged in this and we look at a lot of different -- Juan Pablo brings us a lot of different modeling on the scope. And then in terms of how you structure it, I think that's an interesting thought, and we've given some thought to that. So I think all of that is under consideration. And it's hard to say timing. I don't want to leave the impression that -- we're going to end the call and something new is going to happen tomorrow, but it's very much front and center with our thinking and in front of the board. So that's an interesting idea. You could do some kind of combination of regular dividend, if you will, and then special dividend and there's different ways to structure that. So yes, I think that's a good thought to consider.

We move now to Byron Pope with Tudor Pickering. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just a quick question. In the context of Helmerich & Payne now being the most active domestic land driller. Hans, could you just speak to the facility that you guys have at least outside Tulsa for repairing and overhauling rig equipment and how you think about that impacting the overall R&M cost structure for the company and going forward versus maybe some of your smaller competitors who don't have that heft.

Yes. Well, it's a facility that we have up and running now and it plays to what you're asking about which is how do you leverage off the size of your fleet. And then also just how do you leverage off of your learnings and knowledge base of tying in what we see and how we can measure and capture data for rig performance and for how to better maintain those rigs, keep the very low as we think we'd lead the industry in downtime percentage. And so it's all tied into that, Byron, and I think our guys are making strides on doing that. We really don't have any estimates which is the next logical question that you're asking us. We try to quantify some of the impacts. I mean, we were early on in the process. We're seeing encouragement, and so it makes us want to continue to push forward. But I think we're a little early to give you many more specifics than that right now.

It looks like we have a follow-up from Brad Handler with Jefferies. Brad Handler - Jefferies & Company, Inc., Research Division: My peers have answered some of the questions about free cash flow and stuff. I withdraw the question.

Okay. Well, thank you very much, everybody, for joining us, and have a good day.

This does conclude today's conference. You may disconnect at any time. Thank you and have a great day.