Patterson-UTI Energy, Inc. (PTEN) Q2 2011 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Second Quarter 2011 Patterson-UTI Energy, Inc. Earnings Conference Call. My name is Dominique, and I'll be your coordinator for today. [Operator Instructions] As a reminder, this call is being recorded for replay purposes. I would now like to turn the conference over to Mr. Geoff LLoyd, on behalf of Patterson-UTI Energy, Inc.

Thank you, Dominique. Good morning, and on behalf of Patterson-UTI Energy, I'd like to welcome you to today's conference call to discuss the results of the 3 and 6 months ended June 30, 2011. Participating in today's call will be Mark Siegel, Chairman of the Board; Doug Wall, President and Chief Executive Officer; and John Vollmer, Chief Financial Officer. Again, just a brief reminder that statements made in this conference call, which state the company's or management's intentions, beliefs, expectations or predictions for the future, are forward-looking statements. It's important to note that actual results could differ materially from those discussed in such forward-looking statements. Important factors that could cause actual results to differ materially include, but are not limited to, deterioration in global economic conditions; declines in oil and natural gas prices that could adversely affect demand for the company's services and their associated effect on rates, utilization, margins and planned capital expenditures; excess availability of land drilling rigs and pressure pumping equipment, including as a result of reactivation or construction; adverse industry conditions; adverse credit and equity market conditions; difficulty in integrating acquisitions; shortages of equipment and materials; government regulation; and ability to retain management and field personnel. Additional information concerning factors that could cause actual results to differ materially from those in the forward-looking statements is contained from time to time in the company's SEC filings, which may be obtained by contacting the company or the SEC. These filings are also available through the company's website and through the SEC's EDGAR system. The company undertakes no obligation to publicly update or revise any forward-looking statement. Statements made in this conference call include non-GAAP financial measures. The required reconciliations to GAAP financial measures are included on our website, www.patenergy.com, and in the company's press release issued prior to this conference call. And now it's my pleasure to turn the call over to Mark Siegel for some opening remarks. Mark?

Thank you, Geoff. Good morning, and welcome to Patterson-UTI's conference call for second quarter 2011. We are pleased that you're able to join us this morning. As is customary, I will start by briefly reviewing the financial results for the quarter ended June 30, 2011, and the year-to-date. I will then turn the call over to Doug Wall, Patterson-UTI's President and CEO, who will make some detailed comments on each segment's results, as well as sharing some operational highlights for the quarter. After Doug's comments, I will share a few brief thoughts on general market conditions. As usual, following our prepared remarks, we will take your questions. At the outset, let me say that we were very pleased with our results from both businesses during the second quarter. The improvement in our business is seen in the revenue increase of 95% and the net income increase of 176%, as compared to the same quarter a year ago. During the second quarter, we continued our trend of 7 consecutive quarters of improvements in revenues and profitability in both our Drilling and Pressure Pumping businesses. Moreover, despite the effects of annual spring breakup with its road and location restrictions in Canada and Appalachia, we were able to achieve continued sequential quarterly improvements in revenues and profitability in both our Drilling and Pressure Pumping businesses. As set forth in our earnings press release issued this morning before market open -- opening, we reported net income of $81.6 million or $0.52 per share for the 3-month period ended June 30, 2011, and $153 million or $0.98 per share for the year-to-date. This compares to net income of $29.5 million or $0.19 per share and $33.7 million or $0.22 per share for the comparable 3- and 6-month periods in 2010. Revenues for the quarter were $600 million compared to $307 million in the same quarter last year. And for the 6-month period, revenues were $1,167,000,000 -- $1.16 billion compared to $579 million. On a sequential basis, total company revenue improved by $33 million or approximately 6% despite the impact of spring breakup. Worth noting, on a sequential basis, both U.S. Drilling revenue and our Pressure Pumping business both improved by 11%, $37 million for U.S. Drilling and $20 million for Pressure Pumping. But, of course, the overall increase is a smaller due to the significant seasonal decline in Canadian drilling due to breakup. EBITDA for the quarter improved to $235 million, which represented a $21 million improvement over the preceding quarter. Our company's achievements in the second quarter reflect 8 consecutive quarters of growth in EBITDA. EBITDA margin was 39.1% during the second quarter, an improvement of 150 basis points over the first quarter. For the quarter, capital expenditures were $245 million. Most of this CapEx continues to relate to our Apex rig newbuild program. We completed 8 rigs in the quarter and expect to complete 2 more by the end of July. Accordingly, we now expect to have completed 13 rigs through July, and we expect to meet our target of 25 new rigs for the year. With respect to our Drilling business. We have now witnessed, through June, 24 months of consecutive growth in our U.S. rig count. And the uptrend in the U.S. rig count has continued and increased through July to date. As we have said, the continued increase in active rigs demonstrates that our diverse rig fleet, both the new advanced-technology rigs, as well as our strong base of conventional rigs, is important for satisfying our customers' overall needs in many different markets. Strong crude oil prices continue to drive much of the increase in activity, and we, with our rig and geographic diversity, have been able to capture our share of this newly resilient domestic oil- and liquids-rich markets. Currently, approximately 55% of our active U.S. rigs are drilling primarily for oil and liquids, and we expect this number to grow through the next couple of quarters. Most significantly for our Drilling business, we now have approximately 55% of our rigs working under long-term contracts. Moreover, all of our new Apex rigs scheduled for delivery during the balance of 2011 are now covered by long-term contracts. Our customers' strong interest in term contracts reflects, we think, their confidence in the duration of the current uptrend in land drilling and Patterson-UTI's ability to provide both advanced-technology rigs of the highest capability, as well as high-quality conventional rigs. Moreover, they see Patterson-UTI as one of their prime suppliers for rigs. In light of this strong customer demand, we are planning to increase our production of new rigs from approximately 25 to 30 rigs for 2012. As we see it, the increasing significance of oil- and liquids-rich drilling, along with the increasing long-term contract coverage, gives us a predictable base of strong revenues and expected income. Our significant fleet of conventional rigs adds an option to the value to our company, particularly when natural gas prices increase. Our Pressure Pumping business had another good quarter. In terms of expectations, we said on our last call that we expected revenues for the Pressure Pumping business to increase on a sequential basis approximately 10%, despite the effects of spring weather on our operations in the Northeast. We exceeded that estimate despite revenue loss from moving certain equipment from one market to another. Prices for our services continue to increase, and we are extremely optimistic about this business going forward, particularly as we take delivery during the second half of the year on the additional pressure pumping equipment we have on order. Based upon what our suppliers are telling us, we now expect that deliveries of approximately 142,000 horsepower of new pressure pumping equipment that is slated for the second half of the year will occur in roughly equal installments, with half occurring towards the end of each of the third and fourth quarters. We do not see signs of overcapacity in the near term, and in fact, see continued shortages of equipment and waits by customers for available equipment. The upward trend in drilling, along with faster replacement cycles, shorter equipment life and increasing service intensity, will continue to balance the supply-and-demand forces in this segment. For that reason, we are planning approximately 140,000 of additional horsepower for delivery in 2012. As we have said, pressure pumping is a core business for Patterson-UTI. The increased significance of our Pressure Pumping business was again reflected in the second quarter, as this business accounted for 33% of revenue and 28% of EBITDA, as compared to 19% and 12%, respectively, one year ago. I would now like to turn the call over to Doug, who will further discuss our operations for the quarter.

Thanks, Mark. I'll start this morning with some commentary on the drilling company before turning things over to Pressure Pumping. As Mark has noted, the second quarter was another very solid quarter for us, highlighted, I think, by a number of things: Improvements in activity, higher margins, long-term contract growth, as well as a newbuild contract signings with existing and new customers. For the quarter ended June 30, 2011, the company had an average of 202 drilling rigs operating, including 199 rigs in the U.S. and 3 rigs in Canada. This was a 7-rig increase over the U.S. -- or in the U.S., over the average activity levels we experienced in the first quarter. The Canadian rig count, as expected, fell from 15 rigs in the first quarter to 3 rigs in the second quarter, causing a revenue drop of some $27 million sequentially in this region. Both the U.S. and the Canadian rig counts reflect the current strong state of demand for our rigs. We expect our July rig count to average approximately 215 rigs operating, comprised of 205 in the U.S. and 10 in Canada. This represents an increase of 50 rigs in the U.S. and 3 rigs in Canada compared to July 2010. We expect that the U.S. rig count will have increased by 4 rigs and the Canadian rig count by 6 rigs for the month of July, as compared to the month of June. For the third quarter, we're now expecting to average approximately 220 total rigs operating. This is based on running 209 rigs in the U.S. and 11 rigs in Canada. Average revenues per operating day for the second quarter were in $21,000, a sequential improvement of $760 per day. Rig pricing continued to improve with significant price increases in certain geographic markets, primarily those driven by oil and high-liquids content. Some of this revenue increase is also attributable to the pass-through of a wage increase implemented during the quarter. Average direct operating costs per day increased by $150 to $11,880 for the quarter. While our daily labor costs increased quarter-to-quarter I am pleased to say that we maintained a tight rein on our other operating expenses, including repairs and maintenance costs, which held the overall increase in costs to approximately 1%. Overall, our operating margins per day increased by $600 to $9,110 per day, certainly better than we had expected. For Q3, we anticipate that our average revenue per day will increase by a further $500 per day and our operating margins will improve by approximately $350 to $400 per day. Overall, we believe we are very well positioned to benefit from any further incremental demand in the liquids-rich and the oily basins of the U.S. We continue to see strong customer interest in our high-quality conventional rigs, and we expect to see additional demand in this area in the coming month. The demand for newbuild rigs also remains very strong. With respect to long-term contracts, I'm pleased to say that we made excellent progress in the second quarter by signing up 28 long-term contracts, including 10 for newbuilds, 6 existing Apex rigs and 12 contracts for conventional rigs. So based on contracts currently in place, we now expect to have an average of 122 rigs working under long-term contracts during the remainder of 2011. Last quarter, we had announced we had 102 rigs working under long-term contracts during the rest of '11, thus we have seen almost a 20% increase in term contracts during the last 3 months. Let me spend a few minutes this morning now, giving you a quick recap of our newbuild program. In terms of the delivery schedule, the 8 rigs that Mark mentioned earlier, that were completed during the quarter, was a new all-time high for us. These 8 new rigs worked approximately 250 days during the quarter. Of the 8 rigs, 4 were Apex Walking Rigs and 4 were Apex 1500. 4 of the 8 were deployed in the Eagle Ford, 2 in the Appalachians and 1 each in the Rockies and West Texas. A particular note, this is the first newbuild rig we have deployed into West Texas in recent history, and I think it's noteworthy that this market is now providing us with the appropriate contract terms. I also want to point out that the newly delivered walking rigs drilled wells in both the Eagle Ford and the Utica shales during the quarter. Our walking-rig technology has now been successfully deployed in 8 of the major resource plays in the U.S. and continues to attract new customers and grow market acceptance. In terms of capital expenditures, the drilling company spent approximately $197 million during the quarter. In addition to the 8 newbuilds I talked about just a minute ago, we also deployed one major refurbished rig to the Bakken on a long-term contract. Other than the drawworks, which was completely overhauled, this rig is now totally new. Although we do not determ [ph] it an Apex rig, for all intents and purposes, it is a brand-new rig. So with our rig up yards now in high gear, we expect to complete a similar number of rigs during Q3 and expect we will be able to meet all of our delivery commitments for 2011 rigs. So in addition to the 25 new rigs expected to be completed in 2011, we also now expect to build 30 new rigs in 2012. We currently have a number of long-term contracts awaiting signature. We are sold out of new rigs through the end of the year, and needless to say, we're delighted with our progress in signing new contracts. We expect this momentum to continue as we progress through the remainder of this year and into next year. So that concludes my remarks this morning on Drilling. So let me now turn to the Pressure Pumping business. Revenues in our Pressure Pumping business totaled $200 million for the quarter, slightly above our expectation. Both the demand for equipment and pricing remains very strong in this segment, as evidenced by the 17% increase in gross profit on an 11% increase in revenue. EBITDA for pressure pumping totaled $66.8 million, up over $10 million from last quarter. Let me make a few comments on each of our operating regions, starting with our Texas operations. We continue to be extremely pleased with the operational and financial performance from this segment of our business. Activity levels remain very strong in both the Eagle Ford and the Permian markets. In terms of pricing, our overall frac discounts during the quarter improved by 3 percentage points. We remain very bullish about both the Eagle Ford and the Permian markets and are currently in negotiations with several customers on providing dedicated equipment on a take-or-pay basis. A couple of operational highlights. I think they're noteworthy, and I'd like to share it with you this morning. We deployed our newest frac crew, some 40,000 horsepower, in South Texas in the early part of June, pretty much on schedule. The crew's first job was for a major customer in the Eagle Ford, where we employed 2 large shale frac crews on one location, and we pumped a simul-frac on a 5-well pad. The 80,000 horsepower deployed on this one location is certainly a new record for Universal, and I think it's a true testament to our technical and operational capabilities. In addition, during the quarter, we redeployed almost 40,000-horsepower out of the Barnett Shale and moved it into both the Permian and the Eagle Ford markets. We are achieving higher rates of utilization and better returns with this redeployment. Although we did lose a few pumping days and we incurred some additional costs related to the move, we feel this positions us in well more active markets moving forward. Turning to our Appalachian business. Our Q2 performance set an all-time record for Universal Well Service. Revenues and EBITDA were the highest in our 30-year history. And I think even more impressive is the fact that we accomplished this growth with only 11,000 more horsepower than we had in Q1. The Marcellus Shale continues to drive our activity in this region, and we're now starting to see the signs -- I think, the first signs of the potential of the Utica. Our newly opened Williamsport base pumped 214 stages this quarter and accounted for almost 1/3 of our overall revenue in this market. The opening of this new northern base has certainly allowed us to reduce both labor costs and sand hauling costs to meet the needs of this growing market. I'm also pleased to announce this morning that during the latter stages of the quarter, we signed a new term contract with a major player in the Marcellus. This contract commits some 35,000 horsepower on a dedicated basis for a term of 2 years. In total, as Mark mentioned earlier, we have an additional 142,000 horsepower still to come this year, approximately half of this additional capacity should be in place by the end of the third quarter with the other half in place by the end of the fourth quarter. We see ongoing demand for incremental pumping services well into 2012 and are currently in discussions with several customers for additional committed crews. We currently have approximately 135,000 horsepower of our frac horsepower working under long-term contracts. The industry continues to face tightness in labor markets, as well as the challenge of sourcing sand and other materials to meet the needs of these ever-more service-intensive jobs. As a company, we are addressing these challenges head-on. So before I turn the call back to Mark, let me just make a comment or 2 on our expectations for Pressure Pumping for the balance of 2011. As I mentioned before, we expect to end the year with approximately 650,000 pressure pumping horsepower. Lead times for most of this equipment are now approximately 12 months or longer. We are increasing our plans for new equipment in 2012 and are now planning approximately 140,000 horsepower of fracturing equipment deliveries in 2012. With respect to the third quarter, we are expecting a sequential increase in revenue of approximately $25 million to $30 million and an increase in gross margins from 35.6% in the second quarter to approximately 37% in the third quarter. So with that, I'll now turn the call back to Mark for some concluding remarks.

Thanks, Doug. As I said at the outset, we are very pleased with the operating and financial results for the quarter, as well as the tremendous progress we've made on a number of strategic fronts. Our management team believes that Patterson-UTI has achieved a significant transformation and is poised for continued growth. Shale and other unconventional plays have, of course, radically changed the U.S. energy landscape as domestic production becomes both more plentiful and available at competitive prices with other world suppliers. In turn, these shale and other unconventional plays have been made possible by improvements in horizontal drilling and improved fracturing techniques. Drilling and fracturing, gateway technologies for the improved U.S. energy supply, have themselves seen fundamental changes in required equipment and personnel. As the drilling and fracturing landscape has changed, so too has our company fundamentally changed to meet our customers' needs. It should [ph] reflected in the fact that in the past quarter, we generated 82% of our drilling revenue and 77% of our fracturing revenue from horizontal and directional wells. As we see it, in both of our businesses, the trends of increasing number of wells and increasing complexity of wells has resulted in a shortage of new technology drilling rigs and fracturing horsepower. These trends, in turn, prompt increasing demand for advanced technology rigs and for high horsepower frac-ing equipment, and with the increased demand, increases in prices for our services, along with some increases in labor costs. Fundamentally, our progress, in respect of the strategic plan, has arisen from our commitments both to the equipment and the people. We have, as is evident from our CapEx program, spent substantial amounts to be able to meet our customers' needs for equipment of the highest regard. We have as well spent substantial amounts to train and retain our people, so we have the right people to handle the work. Our operational and financial results show that we are achieving improving results both on a year-over-year basis and a sequential quarterly basis. These improvements have come over a number of quarters and have been achieved even during periods in which weather and other uncontrollable factors were hindrances. Likewise, we are pleased that investors appear to be noticing the recent changes in our company, the pronounced period of improvement and the greater stability of revenue and earnings. The stage is set for the next step upward, and we are as optimistic about the business as we have ever been. In closing, I am pleased to announce today that the company declared a quarterly cash dividend on its common stock of $0.05 per share to be paid on September 30, 2011, to holders of record as of September 15, 2011. Finally, I'd like to take a moment to thank, personally, and on behalf of our entire management team, all of our colleagues who make Patterson-UTI the company that we are. We have a talented and dedicated workforce, and we salute and thank you for your service. Please know how proud we are of what you do. Thank you. At this point, operator, I'd like to open the call for questions.

[Operator Instructions] Your first question comes from the line of Marshall Adkins of Raymond James. J. Marshall Adkins - Raymond James & Associates, Inc.: Question, let's start out on Pressure Pumping. You're adding a lot of capacity here. By my math your adding just under 15% of -- to your Pressure Pumping capacity last quarter, maybe another 30%, second half and grow another 20% next year. What we've seen with some other guys is a lot of startup cost issues. It doesn't seem like you had those in the second quarter. Can you give me some color on what happened in the second quarter with startup cost for those new crews? And should we expect some margin moderation because of the amount of capacity you're adding so quickly?

Marshall, this is Doug. Quite honestly, there is a number of startup costs in our numbers in the quarter. When we get those frac crews ready to go to the field, they're really employed. They're working on other crews. So those costs are there. They're probably there for a month to 6 weeks before the crews -- the new frac crew actually start. But with the way we've got new equipment deployed, really, for the next 12 to 18 months, I think you're going to see those costs virtually every quarter. J. Marshall Adkins - Raymond James & Associates, Inc.: So -- but it still sounds like you're saying about margin improvements, even though you're going to have those additional costs. Is that fair?

Yes, I think that's fair. A lot of that is a mix issue. And one of the things that we see, the more and more sort of pad-type wells that we frac, the better our margins tend to be. J. Marshall Adkins - Raymond James & Associates, Inc.: Great. All right. Second line of questioning here. On the drilling rigs, you've been adding roughly 10 to 15 a quarter, if you exclude seasonality this year. And number one, do you expect that to continue through '12? And could you break down for me the rigs you're going to add or you think you're going to add roughly in '12 between brand-new ones versus just reactivation of existing versus, let's call, significant refurb-ed rigs, where you really spend a lot of a money to refurb what you have?

Marshall, we've, as you know, been pretty careful about saying that we would speak to this quarter that we're in and not go too far ahead of that. Obviously, when we talk about our new rig program, we're really talking about the number of rigs that we're going to be putting out each year. And we spoke to 25 rigs for 2011 and now 30 rigs for 2012, the new rigs. J. Marshall Adkins - Raymond James & Associates, Inc.: Those are brand-new ones, right?

Yes. But the number we're going to put out, the conventional rigs, frankly, we have not wanted to sort of pinpoint that number, because, frankly, it turns on what the market conditions are. And as you can see from what we did in the prior quarter, the just completed quarter, we've been -- let's put it this way, we've been achieving significant improvements in margin. And we think that's a very valuable way for us to have operated this past quarter. J. Marshall Adkins - Raymond James & Associates, Inc.: Right. Let me maybe come at it a different way. And I'm not asking you -- trying to pin you down on exact numbers. But just directionally, do you have more capacity that you could either refurb or reactivate as you go into '12 and beyond?

Yes. Unqualified yes to that question. We have additional capacity that we can put out there. Marshall, we're -- we look at that additional capacity in putting out rigs, pretty much in terms of, is the demand such that we are confident that we're going to be putting that rig out, not just for 1 well, but for a multitude of wells, that we're going to do so at a price, and obviously, a margin that we think is going to be attractive for us. And can we do it in a way in which we can produce and give the kind of quality service that we want to provide our customers. And if we can meet all those requirements, we'll definitely do it. The question I think you're asking is sort of a narrower question, which is do you have the equipment? Absolutely, and we'll put it out when we meet those objectives. J. Marshall Adkins - Raymond James & Associates, Inc.: Right. That's where I was going. And yes, it does seem like you and everyone else being more responsible in terms of adding that capacity. Final one. Are you -- or are we -- is the bottleneck in the industry today more pressure pumping or rigs?

I think both. J. Marshall Adkins - Raymond James & Associates, Inc.: Equally?

We're seeing customers who are pushing for both services that we provide. And in different markets, different customers speaking about each of those services. And so the commitment that you see to spend CapEx dollars into 2012 reflects the fact that we see demand, in effect, outstripping supply in both areas. So equally, I don't know if I would call it equally, because I don't know that I think about it in those exact terms, but we think we're getting the same kinds of returns on our capital in both industries.

Your next question comes from the line of Jim Crandell of Dahlman Rose. James Crandell - Dahlman Rose & Company, LLC: First question is -- so in -- Doug, I didn't hear you -- I thought I heard you say in talking about your frac equipment that's coming onstream in the third quarter that you were talking to several people about contracts. Is it right that -- that equipment is not yet contracted?

That's correct. We have it -- we have, certainly, some customers today that have spoken for the equipment, but we have not signed a long-term commitment with them. But we're still working towards those goals. James Crandell - Dahlman Rose & Company, LLC: And then that's what you're looking for and you prefer is a long-term contract on your new equipment?

That's certainly what we would prefer. But as I said, there's some customers that today, still, are very reluctant to get pushed into a 2- or 3-year commitment, take or pay. So we have to weigh these things. And each market is slightly different. We're seeing strength in certain markets, and I think you'll continue to see that. But I think as time goes on, you'll see more and more people getting comfortable with longer-term type commitments similar to what we see the Drilling business. James Crandell - Dahlman Rose & Company, LLC: Okay. But we shouldn't -- I mean, you would be very confident about that equipment going on contract as soon as it's available?

Yes, we're -- it's going to go -- it may be a multi-well contract, maybe a shorter-term contract than what we would typically call a long-term contract in the Drilling business. But it's certainly going to work the moment that it's available to go to the field. James Crandell - Dahlman Rose & Company, LLC: Okay. And Doug and Mark, the Marcellus is very important for you. If we're in a -- if we continue to be, let's say, in a $4 or a low $4 gas environment, do you think that the Marcellus can continue to add rigs and strengthen over the course of 2012?

Yes, I think it can, Jim. It may not be at the same pace that we've seen over the last 3 years, but I still think that is one of the basins that probably can survive very nicely on $4 gas, if they have to. I do think you've seen a little bit of -- a lot of people have drilled their commitments. They're -- as opposed to doing development work today, they really are doing a little bit more of what I would call exploratory work. So their focus has changed a little bit. But I -- we're starting to hear signs that they're going to get back to the development-type drilling. So I do think that most frac equipment and, really, drilling rigs will continue to grow in that market. And when I say the Marcellus, I'm also kind of referring to the Utica, which is really right next door. James Crandell - Dahlman Rose & Company, LLC: Okay, good. Another question, Doug, is the newbuilds here for the newer fit-for-purpose rigs have been dominated by you and 2 other companies here. Given now that we're seeing some, I assume, stretching out of delivery time, do you expect to see, or are you seeing other companies entering the market? Or do you expect to see new spec building of fit-for-purpose rigs in the market?

Jim, I think the newbuild programs, certainly, have been dominated probably the 3 companies or 4 companies that you've referred to. However, we always see the ones and twosies from some people that have the capability of building a rig or two. There's no question that I think the supply chain there is getting a little stretched. But the reality is with preplanning and making sure that you've got this stuff coming, recognizing that you're a year out on a lot of this stuff, I think we have some advantages over the little guy that may decide to build a rig but has got to get in line with a whole bunch of other people.

Yes, I guess, Jim, I would just add one thought to that. This is Mark. That not all new rigs are created equal, would be the way I would have put it. And that I think that some new rigs are preferred by customers for certain reasons because of typically their absolute engineering capabilities and their perceived abilities to do certain kinds of things. And we're putting and have been putting over the past several years a substantial focus in what those rigs are capable of doing, and I would just point to you to one particular example of our walking rigs as one particularly easily seen kind of a technological or engineering accomplishment that makes for a rig that has superior capabilities. James Crandell - Dahlman Rose & Company, LLC: And last question, Doug, can you highlight when you might expect the equipment deliveries of pressure pumping equipment in 2012 from a timing standpoint? And sort of -- or as close enough, if you could do that.

I think we're pretty reluctant, Jim, at this point to speak to the quarterly deliveries of 2012. We've spoken about the approximate 140,000-horsepower coming sort of at the sort of end of the third quarter, the end of the fourth quarter. I think we're pretty reluctant to start to project out past -- the end of '11 and into 2012. What we're being told by our supply chain is kind of a 12-month delivery period. And whether that will shorten or extend is the question that we're not -- we're trying to make sure we don't give information that turns out not to be correct because of things that we get told. But that's the kind of process we're employing at this point. James Crandell - Dahlman Rose & Company, LLC: Did you say, Mark, that you even see it more second half weighted? Or is that even uncertain?

Jim, this is John Vollmer. And Doug, correct me if you see this differently. Pressure pumping is a little bit different on equipment deliveries than rigs are. You can say evenly over the quarters and whatnot and one coming out has a revenue impact. The pressure pumping equipment, where you really see the revenue boost is when the whole spread gets there and the size of the spread can vary by where it's going to operate, how big it needs to be. And as we finalized those plans, we could give you more detail. But today, it's not finalized just how those spreads will be configured in all cases.

Yes, Jim, what I think John's really referring to is that we placed orders for this stuff, and we get a projected delivery date. And we could, today, probably give you a rough idea of what the pump deliveries might be, but the reality is the pump's no good unless you got the blenders, and the liquid add equipment and a number of other things. So that's why I think at this point, we're just a little reluctant. We will update you in later conference calls. But today, I don't -- we just don't want to give you something that may not be correct.

Your next question comes from the line of Scott Gruber of Bernstein. Scott Gruber - Sanford C. Bernstein & Co., Inc.: New contracts on legacy rigs appear to be a big driver of the growth in the backlog over the past 2 quarters. Can you provide some details on the rigs and the terms of those contracts and some color on the spec of the rigs being signed on the legacy fleet?

Scott, it's hard to kind of generalize. I guess I would say this, is typically, those rigs are going into 2 or 3 different markets, and obviously they're the markets that are hot at the moment. So it's places like South Texas, and the Midcon, and certainly, the Bakken. The rates have certainly improved typically from a contract basis. You may not be able to push for a 3-year contract. But we've had lots of those, with the customers prepared to sign 2-year contracts at very solid rates. So I hesitate to give you any more specifics than that because obviously, the rate in the Bakken with a winterized rig is substantially higher than the rate of a non-winterized rig in West Texas. But typically, we've seen very nice growth in a lot of our solid, good, high horsepower, even mechanical rigs that there just isn't the market or the availability of newbuilds on a short-term basis.

Yes, I would add that the hard thing, like giving you a kind of a benchmark number for that, Scott, is the problem that you got a rig going into the Bakken winterized with substantial horsepower as compared to a lesser horsepower rig going that's non-winterized into West Texas to very different applications, both of which may be signed to a long-term contract but very different kinds of terms. And so giving you something with specificity, I think, unless we gave you everyone of them would be pretty difficult. And I wouldn't want to do that for obvious reasons, obvious competitive reasons. One thing I think is important that your question is pointing to, though, and is I think just very often overlooked, is you're right, that in development of term contracts for conventional rigs is perhaps one of the most positive developments for our company. We've long spoken about the fact that the conventional rigs are a real asset. And the fact that they're going to work and not just going to work in the spot market but going to work in the term -- under the term contracts really tells you something about the value that's inherent in those rigs. Scott Gruber - Sanford C. Bernstein & Co., Inc.: Right, that's a big opportunity for you, guys. And then turning to the Apex rigs under contract. Can you provide a rough number for the average rate that those rigs are working at, at least in comparison to the spot market? Maybe a percent discount to the current spot you're seeing in the market today?

John?

We typically don't try to give out those numbers just because I think it's a competitive number that I'm not sure we want out there. But I think we've certainly said in the past that those newbuilds can be anywhere from the mid-20s to the sort of the higher 20s. Typically, all of those rigs typically go out on 3-year contracts. We certainly will entertain longer terms but typically for a longer term, the customer is looking for a lower rate. And So if you look at -- I think, all of the term contracts that we signed for newbuilds in the second quarter were all 3-year contracts at very attractive rates. Scott Gruber - Sanford C. Bernstein & Co., Inc.: Right. But you should have a pretty good tailwind just with some of the fit-for-purpose rigs being re-contracted at higher rates over the next few quarters? Those that were originally signed to long-term deals late last year?

Yes, I think that's true. We probably have fewer rigs coming off term contract than potentially some of our competitors. But what I will tell you is that every rig we've had come off term contracts really in the last couple of quarters has typically been renewed, and not necessarily always with the same customer, but we've signed another term contract. And I think for the most part, you can generalize and say they're higher rates.

Scott, the tail on your question made reference to the rigs coming off contract that were contracts previously. I mean, many of those contracts were let in 2008, which was actually a pretty good market. So I think it's going to vary rig by rig whether it's the same or it's higher. But the ones coming off contract are also at pretty good rates, I think. Scott Gruber - Sanford C. Bernstein & Co., Inc.: And then one last one, on pumping. You mentioned the higher margin generation for frac fleets working on pad operations. Can you provide a rough percentage of your fleet that is working on pad today? And how that should ramp over time?

Scott, I really can't give you an answer there. It changes almost day to day. So for me to throw out an answer or anything different than that I likely wouldn't be correct. Scott Gruber - Sanford C. Bernstein & Co., Inc.: So are we talking somewhere in the, like, 20% to 30% range?

It's a real question, Scott, of looking at it on a day-to-day basis because it just changes. And we've got different operations in our Texas-based business, as well as compared to the one in the Northeast. And each of them have different locations, and so you'd be -- in order for us to even try to answer your question, we'd be tallying something we don't actually track as a company. So I don't think there's a person sitting around our table right now who would even hazard a guess at that answer.

If I could add one more thing to that. What I was -- the point I was really trying to make is that we frac on pads that have 2 or 3 wells. We frac on pads that have 16 wells. And the reality is the more wells that are on a pad, the more efficient you can be to get that frac job done. But it's really hard to quantify. I can't give you a number, say, a 16-well frac, you're going to do this in a 2-well. But just all of those things where you don't have to move the equipment, you're not shuffling things around, you just -- we tend to be more efficient and be able to generate higher margins, the more wells that are on a pad.

Your next question comes from the line of Joe Hill of Tudor, Pickering. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc.: Mark, could you comment or remind us on what you think the ideal level of contract coverage is for both your drilling and pressure pumping businesses at this point given your outlook?

Yes. It's an interesting question. Years ago, we were asked this kind of question, and we said that we were happy to, in effect, respond to our customers, and we weren't the ones who wanted to set the bar where we said to ourselves, "Gee, we'd like to have 60% of our rigs or 50% or whatever the number would be," termed up. And we would, in fact, sort of respond to the customers' needs. And I think we have pretty much, as a company, stayed consistent with that view. The thing, though, that we are seeing, that I have strongly believe -- and I throw this to Doug and John to see if they have a different take on it, is that the increased coverage of contracts really stems from the customer saying, "Well, you have equipment, you have a crew, you have a capacity that we want to lock up, and we're willing to and wanting to sign up a 3-year typical contract to lock in that crew and that equipment because we think it's providing a superior service, and we'll pay you a great rate." And we, on the other hand, saying to ourselves, "Gee, the terms of that contract provide very acceptable returns on capital from our perspective as we think about it." So from everybody's perspective, we've gone into those contracts. Where I see the term contract increase as really reflecting the increased perception of Patterson's capabilities in the drilling side. That's really what I see that as and our willingness to tender into those contracts as the terms are attractive. On the pressure pumping side, same point except I'd make one additional point, that we believe that shortages of the frac-ing equipment and delays in getting frac crews are so pronounced in the business that customers are desirous of signing term contracts to assure supply and feeling like if they don't sign that term contract they're more -- they take greater risks of being able to get their wells frac-ed. So that's kind of my answer. I don't think we have a targeted number. We have a response to the market. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc.: Okay. And Mark, I thought I heard you say in your prior commentary that customer waiting times have increased in pressure pumping?

I think I said that there are significant waiting times. I don't think I tried to evaluate whether they've gone up in the last quarter or down in the last quarter. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc.: Okay, fair enough. And then...

Because I don't think I would have any particular insight on that point. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc.: Okay. And I noticed the price book improved a little bit more in the second quarter than the first quarter. Is that a sustainable trend? And what do you think the price book might do in terms of an average for Q3?

I think we gave a comment in regard to expected gross margin in which we said that we thought that gross margin would go from 35.6% in second quarter to 37% in the third quarter on the basis of a $25 million to $30 million increase in revenue, is what we said looking at the move from second to third quarter. So that's really kind of our best thinking. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc.: Okay. So I take it that if you just look at that 100 and, say, 40 basis point improvement quarter-on-quarter, that would assume that the price book probably doesn't improve as much as it did in the third quarter as it did in the second quarter?

I think it's a couple of things that are going on there. We got some probable pricing. We got also some efficiency from not having certain -- crew movements and other kinds of things. It's a very large mix of factors that are taken into account as we try to give some guidance to the next quarter taking into account all the things that we are aware of as we look at it. So, yes, it's something on price. Yes, it's something on cost. Yes, it's something on a number of facts. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc.: Got you. Okay, and then can you talk a little bit about your access to frac sand and how you handle that contractually and what your outlook for that is?

I guess there's no question that we've seen some tightness in the sand markets, particularly the coarser grains, the 2040s, the 3050s. Both our groups are every day and every week are trying to stay ahead of the market. We have been trying not to get too committed with take-or-pay contracts, but we think we're relatively well covered with sand supplies. As I said, this is a very competitive part of this business that I think as an industry, we're all dealing with. And the reality is that our customers change their minds on a dime as to what kind of sand they want on the next well. So we have to be a little bit Houdinis on this kind of thing. And as I said, I'm not going to say too much more other than sand is one of those things that if we don't have sand, we don't pump. So we take a lot of effort of making sure that we've got the right kind of supplies and when -- when and where we need them.

And I have say one more thing to add to what Doug has said, which is that from our perspective ,being agile as a company is really an important virtue. And our guys are very -- are well aware of the issues in respect of the -- for lack of a better word, ingredients, and they know they have to have it, whether that's gel, or sand, or other things, and they do their very, very best to assure supply. But your point of asking the question is, it is a challenge and it is one which our guys work hard to manage. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc.: Okay. And just to clarify a little bit. Under 1-year frac contracts, if you can't get sand, is it your responsibility or is it the operator's responsibility?

Really depends on the contract. We have some contracts where the operator is totally responsible for providing the sand. We have some contracts that we're responsible for providing the sand. But obviously, we have some notice periods and -- that they can't change the grades and the quantities without working with us. So there's both, I guess, to answer your question. But we certainly -- it's not something where they can tell us the day before that, "Oh, by the way, I need 100 tons of this, and since you don't have it, the contract's no good." We have tried to protect ourselves as best we can in those scenarios.

Your next question comes from the line of Robin Shoemaker of Citigroup.

Just a couple of follow-up questions. You talked about there being a price differential in both rigs and pressure pumping between the dry gas basins and the liquids-rich. So I guess for a company the size of Patterson, you really have to be in both. and you're -- but in terms of that differential, how do you -- I guess, obviously, if you have a rig that becomes idle, you'd move it from a dry gas basin to a liquids-rich. But are you looking at every opportunity to move from one sort of basin to another? Or do you feel like there's a rationale for staying committed to some of those core dry gas basins where you've had a long-term presence?

Robin, just to -- of course [ph], I think we may have a misunderstanding. I don't think we intended to say there was any price difference between dry gas and oil or what gas. There was references to markets where winterization is required and some of the markets have higher labor. But I don't think we intended to draw a line between the commodity.

No, I think the only thing that we would say about that, Robin, is that as the industry got more interested in oil and liquids-rich energy, obviously, rigs shifted from certain gas markets to oil and liquids-rich markets. And our customers, in effect, said, "Hey, can you move a rig into whatever area it is, the Permian or wherever, Bakken or wherever, that is a more of an oil or liquids-rich environment and away from potentially the pure dry gas environment." But we see this as pretty much movement with our customers to where they want to be as opposed to us strategically repositioning to the extent to which we see a market that has excess equipment and that we seen in another market where there are shortages, obviously, we redeploy. I'm not sure if that's...

Yes, thanks for that clarification. I assumed otherwise, but...

Robin, if you think about the 40,000-horsepower we've redeployed out of the Barnett, I mean, you could draw the conclusion that dry gas, we moved it to some areas that were oily. But with us, it's -- whether it's a drilling rig or frac equipment, we are going to try and to maximize utilization and maximize our margins and our opportunity for profits. So I think we do that all the time.

Right. Understood. Okay, just one other question. A little bit from left field, but we keep hearing a great deal about the emergence of international shale plays that require horizontal drilling rigs, pressure pumping services, both of which you have now in abundance. And I just wonder if as you survey all this going on outside the U.S., where if any markets or that just broad set of opportunities interest you as a potential source of growth for the company?

You know, Robin, I feel that we have probably as great an expertise in this as just about anybody. But quite frankly, we're not looking to take our equipment internationally just so we can say we're international. We'll go international when we think we've got a situation where there's increased profitability and better returns for our shareholders. I think one of the things that we've always been of the view for a long time is that the North American gas story was in effect underrated and we thought this was going to be a very important market for us, and we concentrated our resources here and in effect, didn't listen to the siren song of going international, just for the sake of being able to say, "Oh, our company's x% international." At this point, I think, that we're likely to find ourselves being asked to move things internationally over some expectable period as our customers do more and more of their work internationally. But it will be as we go with our customers to known situations with pretty known expected returns and not just as a, in effect, experiment.

Your next question comes from the line of John Daniel of Simmons & Co. John Daniel - Simmons & Company International: I want to start with a follow-up on Joe's question about the sand. It looks like we probably added close to 1 million horsepower in Q2. And seems like that rate is going to increase over the next 4 to 5 quarters. If that rate continues, do you think there's sufficient sand to meet that amount of horsepower coming online?

You know, John, it's difficult for me to answer the overall industry situation. I can really only talk to our own. We believe we have enough sand, and we'll continue to be able to get enough sand to meet our requirements, and I really can't comment on the other people. I would assume they're having the same issues we are. But for me to speculate on the overall industry is nothing more than speculation. John Daniel - Simmons & Company International: Okay, worth a try. For next year, 140,000 horsepower on order. Do you have any manufacturing slots reserved above and beyond that so that we can potentially see more horsepower?

John, this point, what we have reserved is the 140,000 horsepower that we told you about. We are every day, we think about this, and we're thinking about, does that number need to be higher? But at this point, we're not prepared to say that we're doing anything more than what we've committed. John Daniel - Simmons & Company International: Fair enough. Q4, on pumping, would you expect at this point any margin compression for seasonality? Or do you think a 37% is reasonable back-to-back. Q3, Q4?

John, we don't speak beyond one quarter. We just don't feel like we have enough visibility. But relative to the general question, I'm not aware of anything relative to third versus fourth that would cause meaningful compression of margin. John Daniel - Simmons & Company International: Okay. Last one for me. Doug talked about the Utica. At this point, I know it's early, do you have any sense as to what typical horsepower requirements would be or thoughts about average stages per well?

John, I really don't. I think the Utica is still in very much a, I would say, almost a secretive -- certainly, on the frac side, I think it's all over the map, and I think the 2 or 3 different customers I've talked to, I don't think there's any general feel at this point. Although I would say I think it's probably somewhere in the order of magnitude of what we're seeing in the Marcellus.

Your next question comes from the line of Dave Wilson of Howard Weil.

Drilling margins have been on the rise, as you mentioned, for some time. And it looks like they're going to increase again. But we're approaching the peak that we saw back in 2006 and early 2007. The way the industry is progressing, now, you think we can get back to those kind of peak margins of 10,000 a day to maybe 11,000 a day at some point? I know you just -- a question was just asked about margins going forward, but the way that's playing out with dayrates continuing to increase, labor costs, et cetera, do you think we can get back to kind of peakish margins?

Let me respond this way. We're -- we, as we've said a couple times already in the call, typically only give some thoughts about what's happening in the next quarter. So and that's what we've been doing. On the other hand, we did say, which I also believe, that we see this trend as part of a long-term trend that's been going on for quite a while. And the real fundamental thing that I think is true here is that starting, whether it's 2008 or whatever date you want to speak to, as the shale plays really changed the business so too the equipment change for drilling, so too the equipment changed for frac-ing. And with the different rig technology, that's why people like Patterson build new rigs to effectively -- that's why we have these Apex rigs, is to, in effect, provide to the industry a very different rig from the rig that has existed historically. And so what the ultimate margins and ultimate dayrates are for those kinds of rigs is something that I think we're not going to know until we get a little longer down this road. I'm optimistic, obviously, we're building 30 new rigs for 2012. We wouldn't be building those rigs if we weren't pretty optimistic about where the business was heading.

Sure. And then one final one, just real quick one, on pressure pumping. You've put the number around the adds in 2012, but do you think there could be some upside to this 140 and if so, given the long lead times, how soon do you think you guys need to act to add potential capacity there?

Quite frankly, we look at these expansions of capital expenditures for 2012. And we look at our CapEx every quarter. And we say to ourselves, "Okay, what do we think we want to have at what point, and what's the delivery times?" And that's how we come to the decision about what to plan for and the information that was put out today. We'll do the same thing at least 2x during the next -- this quarter that we're in the midst of now and take another 2 looks at it, hard, and then in next conference call kind of give you whatever our then best thinking is. I wouldn't rule out the possibility that it goes up. But I'm also not prepared to tell you that it's going to go up because where we are today is where we are.

Your next question comes from the line of Ryan Fitzgibbon of Global Hunter Securities.

Quick question on the legacy side of the business. You mentioned you signed 12 additional contracts for legacy rigs during the quarter. Were any of those for incremental rigs going back to work that were previously stacked?

Yes. I can't give you the number exactly, but the answer is yes.

Okay. I guess, any thoughts on the second half of the year? How many incremental rigs that are stacked right now that could go back to work at returns that could pay back in 6 months to a year?

We've -- I'll give you the West Texas example. We know today that we've got 4 or 5 rigs going back to work in West Texas that are currently stacked, and there's a number of other markets where today we know. So I can't give you the total number because, obviously, there are some ups and downs in our business. But I'm currently aware of a number of rigs today that are stacked that we're getting ready to meet an operator's program or requirements here in the next 3 to 6 months.

And then I guess as we look at margins in the back half of the year, those are obviously less than the newbuilds you're bringing in. But the newbuilds are coming in at high enough rates that'll continue to build margin in Q3, Q4. I know Q3 your guidance is up, but Q4 looks the same?

We couldn't speak to Q4 at this point in time. It would be early. But rigs that were activating are also getting good margins in addition to the new rigs.

And then jumping over to the pressure pumping side. You're in 2 major markets. Any thoughts on which is the most under-supplied right now and how much your capacity in the back of the year is going to Appalachia? How do you see that in 2012? And any thoughts on where that 2012 capacity goes?

No, we have -- the stuff that's on order, we're under conversations, as I said, with various customers. We've said earlier, that to some degree, our preference is putting it in markets where we can get a long-term commitment. So at this point, we're really not prepared to say where we believe that equipment could go. We are at a point that the equipment we order really could go in either of those markets or it could go into new market if we so choose. So we're really not at a point today where we're prepared to say, "x amount of it is going here, and x amount of it is going there." We have a number of markets that are very active today, and we're trying to sit here and say, "What are they going to be like 12 months from now?" I think as we get closer to the delivery times, it'll be obvious where we're going to put that equipment.

And then would you consider moving current capacity into a new market, whether it be the Rockies, Midcon? Or Are you confident with, I guess, where your capacity is now that it stays there and continues to work?

Well, we're pretty happy with -- we feel that the capacity we have today is actively engaged in the markets that it's in. I think as that changes over time we certainly will look at new markets. We're just not prepared at this point to say we're jumping into some new markets. But obviously, we're in 2 prime markets today, and there's a number of other markets that are pretty hot. But just like with drilling rigs, you how to do a look of a preplanning and make sure you got the infrastructure to move to new markets.

Understandable. I guess last one for John. Can you give the SG&A, DD&A and tax rate guidance for Q3?

Yes. I think, tax rate for the year, I think'll be about 37% to 37.1%, and that's for the year. I'd apply that to the third and fourth quarter. In terms of DD&A, as I estimate it, I expect this to go up about $5 million a quarter based upon our current capital run rate. And in terms of SG&A, I would expect it to be around $17 million in the third quarter.

You next question comes from the line of Arun Jayaram of Crédit Suisse. Arun Jayaram - Crédit Suisse AG: I wanted to talk to you guys in terms of your Pressure Pumping segment and just the broad questions related to potential efficiency gains from here. So just trying to calibrate if there's opportunities as you move to 24-hour type of work to see additional efficiency gains. Or as we think about your revenue growth gets moving forward, it'd be driven largely by just increasing capacity or the number of jobs going forward?

You know, Arun, I think there's opportunities for efficiencies in the frac-ing business. This whole notion of the kind of refrac-ing [ph] work we're doing is in its infancy, if you start to think about it. And so the opportunities to -- for our customers working with us to drive further efficiencies into this business, I think, are pretty significant. And we talk about this all the time, as do our customers and as we suspect, do our competitors. We think there are opportunities. Exactly how all this plays out in terms of our being able to reduce our costs, what our customers may want us to do in return, pretty hard to get a clear fix on it at this point as to how it all plays out. That's the reason why we're speaking to it in such short terms. But fundamentally, I believe this industry, the frac-ing side of the business, will get more efficient and on both the customer side and the supplier side. And let me tell you something. We're very optimistic about this business. Obviously, the announcement of the incremental capital expenditures is pretty [ph] cognizant of the fact that the industry's adding capacity. But we're doing it, too. But we think we have some insights as to what the world will offer. Arun Jayaram - Crédit Suisse AG: Fair enough. I guess my second question is related. Can you give us a sense of how many reactivations you've done year-to-date, just backward looking?

On the drilling side? Arun Jayaram - Crédit Suisse AG: Yes, sir.

Reactivated. I really don't have a number. Arun Jayaram - Crédit Suisse AG: Okay. Do you have a ballpark number?

I guess you could almost back into something that'd be close. If you think that the rig count from last year to this year, our rig count has gone up 50 rigs, roughly, 20.

I think it's about 50-50.

50-50.

25 each would be a kind of a reasonable quick, back-of-the-envelope guess, Arun. But I -- that's a guess, and it's a back-of-the-envelope guess. Arun Jayaram - Crédit Suisse AG: Other couple of quick questions. Guys, we've seen some pretty big operators in both the Barnett and Permian yesterday with Oxy talk about increasing CapEx into that market. In regards to that, are you seeing incremental demand for legacy rigs today [ph] in those markets?

Yes, I think we are. I mentioned in one of the questions just a little earlier. I know of 5 rigs that we're getting ready today to go to work in West Texas in kind of the next 90 days. And there's a number of other markets around, primarily the oily markets, where we've got similar-type rigs getting ready or we're aware of reactivation. So I think it's continuing. Arun Jayaram - Crédit Suisse AG: Got you. Doug, do want to ask you about the Utica, which has been -- there's been a lot of intruders [ph] in there, in the Marcellus a couple of weeks ago, just followed your trip up there. But are you in the Ohio part? Or are you in Ohio Harrison County? Are you in that area yet? Or are you still more in Pennsylvania?

Well, we're -- we've drilled some wells over there. The other nice thing in our Pressure Pumping business, we have a very strong base of operations over in Ohio. And some of the rigs that have drilled in the Utica to date, they may be operating not necessarily out of Ohio, because they seem to go in and drill a well and then pull out. But we're watching that whole area very closely. And primarily now in Pennsylvania, we've got 2 operations base, one in south, one in the north. I think as the Utica develops, we will have to figure out what, if any, infrastructure we need over there. But we do have a pretty big leg up, and one of our sister companies is already there. Arun Jayaram - Crédit Suisse AG: It seems like you'd be really well positioned should that liquids part of the play to take off, which according to Chesapeake, seems to be the case.

Yes. We're pretty excited about it too.

Your next question comes from the line of Judson Bailey of Jefferies & Company. Judson Bailey - Jefferies & Company, Inc.: Most of my questions have been answered, but I just -- one follow-up on your newbuilds. The incremental 5 that you announced in the release, any minimal [ph] change in construction costs there, in terms of newbuild cost?

John, I'd answer that this way. I think -- we've got 3 different models of rigs and for some period of time, we've been talking about rigs in the $18 million range. I think today, we're considering that those costs are probably closer to $19 million. But some of it depends. Our walking rigs typically are all winterized. So there's -- we're really not comparing apples-to-apples. And it really does depend on the type of rigs that we've built for those incremental 5, which we really haven't determined today. I think we mentioned to you some quarters ago that we've really moved towards a kind of a standardization of our rigs, so that much of the equipment is the same and then at the very -- once we know a customer direction, really all we have to do is put up a sub and mast on things. But virtually all the other components of the rig are very, very similar. But getting back to the costs. Costs have crept a little bit. But a lot of it is just we keep adding efficiency-type things. We've added the BOP handlers. We've added all sorts of different equipment. And so it's not just a cost creep on the rig itself. There's certainly -- we continue to make improvements to kind of have state-of-the-art rigs in the field today. But on average, were looking this year at approximately $19 million. Judson Bailey - Jefferies & Company, Inc.: And then just to remind me, that $19 million, that would not include any winterizing or drill pipe or anything of that nature?

Well, I'm just saying that's an average between the 2.

It excludes drill pipe, but you're taking an...

Some drill pipe but average on the other. Some with, some without. Judson Bailey - Jefferies & Company, Inc.: Okay, and then just one other follow-up, I guess, on some of the Utica commentary. Do you have -- can you say if -- what kind of visibility you have from your customers talking? I mean, do you have contracts that are signed? Or are they -- do you have, I don't know, any idea of when you may be putting some rigs in there? Just maybe talk about any more color about the timing on when you think that market could start to really make a difference for you guys.

We really don't have any visibility today that I would be prepared to share with you. I do think that what's happening now is that, that market is so close to the existing Marcellus markets, that they're almost doing it as a little bit of a step-out from the Marcellus. So typically, they're moving rigs -- the closest rigs they've got, they're moving frac equipment. But at some point in time, I think it will become its own unique market all unto itself. And I think that answer probably would better be coming from our customers, the Chesapeakes and the Ranges and all the other people of the world that are pretty excited about the Utica.

[Operator Instructions] And your next question comes from the line of Geoff Kieburtz of Weeden & Co. Chris Enright - Weeden & Co., LP: This is actually Chris in for Geoff. Just a couple of quick questions on the pressure pumping side. Is sand the most constrained part of the frac supply chain?

I don't know if I'd say that. I think it varies week-to-week, the type of jobs, I mean, labor, sand. At various times we've had issues with gel. I'd hesitate to say sand is the biggest issue. There's just a number of things that change week-to-week, month-to-month, and we just have to deal with them. Chris Enright - Weeden & Co., LP: Do you kind of think of it in terms of level of inventory of sand? In terms of days or weeks of frac jobs?

I think it's about supply, and it's about trying to be sure that you have the supply of what you need for your particular thing. You can meet that supply with contract, you can meet it with inventory, you can meet it any number of ways. And so it's a question of if you're obliged to provide it, do you have a source? Chris Enright - Weeden & Co., LP: And just a second question on pressure pumping. In terms of the horsepower that's being added, what is about the incremental sand consumption per added horsepower?

Again, I really couldn't answer that. It really depends on the customer's well program. So as I say, we really can't give you that answer. Chris Enright - Weeden & Co., LP: Okay, fair enough. Sorry, one more question. Last question. Percentage of the pressure pumping horsepower in the fleet. That's either on -- however you want to break it down, 24/7 operations or 18/7, not sure the right way to think about it. But is there much more that can be gained by better utilization or more utilization of the existing equipment?

Chris, we don't have a number here on what portion is on which currently. In the Northeast they don't tend to do 24-hour operations for the most part. It's something less than that. And if customers elect to go there, that could generate higher utilizations, but we don't have the numbers here at this moment that we can tell you what portion is on which schedule. Chris Enright - Weeden & Co., LP: Any sense if there was a change from, say 1Q to 2Q, excluding any weather impact?

I don't think so.

This concludes our Q&A session for today's call. I would like to hand the call back over to Mr. Mark Siegel, Chairman of the Board.

Thank you, Dominique. We thank everybody for their participation in our second quarter conference call. Look forward to everyone's participation at the end of the third quarter. Thank you.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect, and have a wonderful day.