Patterson-UTI Energy, Inc. (PTEN) Q3 2011 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Q3 2011 Patterson-UTI Energy Incorporated Earnings Conference Call. My name is Laura, and I will be your operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to Jeff Lloyd on behalf of Patterson-UTI Energy. Please proceed.

Thank you, Laura. 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 9 months ended September 30, 2011. Participating in today's call will be Mark Siegel, Chairman; Doug Wall, President and Chief Executive Officer; and John Vollmer, Chief Financial Officer. Again, just a quick 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; decline 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 statements. Statements made in this conference call include non-GAAP financial measures. The required reconciliations to GAAP financial measures are included in the company's website 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?

Thanks, Jeff. Good morning, and welcome to Patterson-UTI's conference call for the third quarter of 2011. We are pleased that you are able to join us today. As is customary, I will start by briefly reviewing the financial results for the quarter ended September 30 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 make a few brief -- I will offer a few brief thoughts on general market conditions. As usual, following our prepared remarks, we will take your questions. First, I'd like to begin with a quick recap of the financial results. As set forth in our earnings press release issued this morning before market opening, we reported net income of $81.9 million or $0.53 per share for the 3-month period ended September 30, 2011, and $235 million or $1.50 per share for the 9-month period. This compares to net income of $29.4 million or $0.19 per share and $63.1 million or $0.41 per share for the comparable 3- and 9-month periods in 2010. The financial results for the 3 and 9 months ended September 30, 2011 include pretax impairment charges of $4.3 million or $2.7 million after-tax from the retirement of 22 of the company's rigs. Components from these rates are now available as spare parts to support other rigs in the fleet. These retirements reduced net income per share by $0.02 for the 3- and the 9-month periods ended September 30, 2011. Revenues for the quarter were $674 million compared to $379 million for the same quarter last year, and for the 9-month period, revenues totaled $1,840,000,000 compared to $957 million. EBITDA for the quarter improved to $243 million, which marks the ninth consecutive quarter of growth in EBITDA driven by increases in both of the 2 core businesses. Before turning to CapEx, I want to highlight that these results show substantial improvements in key year-over-year metrics for the 3- and 9-month periods. On a year-over-year basis, revenue increased by 78% on a quarterly basis and by 92% on a 9-month basis, and net income increased by 179% on a quarterly basis and by approximately 272% on a 9-month basis. I'd now like to go to CapEx and give a quick recap. For the quarter, capital expenditures were $284 million. This spending is, of course, consistent with our long-term strategic plan, and a large majority of this CapEx continues to relate to our Apex rig new build program and to our continued expansion of our high-horsepower frac fleet. As expected, our new rig construction program completed 7 new rigs in the quarter, which brings our total of new rigs completed through the end of the third quarter to 18 rigs. We expect to complete 7 rigs in the fourth quarter, and thus we are on pace to meet our overall target of 25 new rigs for the year. In addition, on the pressure pumping side, we took delivery of 76,250 of additional horsepower during the quarter, which brings our total through the third quarter to 138,750-horsepower. Similarly, we expect to be able to deliver in the latter part of the fourth quarter an additional 65,500-horsepower and to be able to meet our overall delivery target of 204,250-horsepower for the year. I'd now like to make some comments on our results. As a starting point in our discussion of both our financial and operations report, I'd like to contextualize these results. As everyone is well aware, the third quarter was marked by a drumbeat of economic concerns reported on nightly news shows, first about the U.S. credit downgrade, then about potentially slowing global and national economies, then about a possible second recession, and then a possible second credit crunch. Predictably, these concerns, along with the accompanying volatility in commodity prices, triggered concerns that demand for oil services including drilling and Pressure Pumping would decline. In the face of these expectations, both our drilling and Pressure Pumping businesses continued their upward revenue and cash flow trajectories, driven by continued increases in activity and pricing. For drilling, revenue increased on a sequential basis by 13%, an increase of approximately $50 million. For Pressure Pumping, revenue also increased on a sequential basis by 13%, an increase of approximately $25 million. Our businesses continue to benefit from the increased activity associated with oil- and liquids-rich plays and our investment in high-quality new equipment. The evolution of our rig and fracturing fleets is reflected in the portion of our revenues from horizontal and directional wells. For the third quarter, 83% of our drilling revenue and 74% of our fracturing revenue was derived from these types of wells. In drilling, we saw our average number of rigs operating increase by 14 rigs from the month of July to the month of October, with roughly half coming from delivery of new-build rigs and the remainder from activation of conventional rigs. Once again, this continued increase in active rigs demonstrates that our diverse rig fleet, both 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. Through the end of September, we have now seen 27 consecutive months of increases in our U.S. rig count. I cannot adequately praise our drilling operations and sales management for this accomplishment. This trend is continuing, as we expect to average 218 rigs operating in the U.S. in October, an increase of 6 rigs over our count in September. More significantly, we expect a steady upward trend in rig count seen throughout 2011 will continue during November and December. As Doug will report, we continue to see increases in term contracts for drilling rigs and we currently have long-term contract revenue backlog of approximately $1.7 billion. We also saw an average revenue per operating day increase during the quarter by $440. This further underscores our view that the North American land-drilling story is very much a continued growth story. While increases in utilization and pricing were, of course, gratifying, we were disappointed by the increase in costs per operating day in drilling, an increase of approximately $1,100 per day. This increase arose from 2 main sources: Increase in labor costs and increase in repairs and maintenance costs, along with associated supply costs. To be more specific, labor costs in the U.S. increased by approximately $400 per day, and repairs and supply costs in the U.S. increased by approximately $500 per day. Doug will, of course, provide more specific information concerning these costs and our expectations on per-day rig costs going forward. The results in our Pressure Pumping segment are coincidentally similar. In the third quarter, our Pressure Pumping business achieved a 13% sequential increase in revenue. This increase occurred despite the interruption of operations caused by hurricane-related flooding in Appalachia in early September and some interruptions caused by ownership changes among our EMP customers. As we have said before, revenue in the Pressure Pumping business is less regular and less predictable than drilling, what my colleague, John Vollmer has characterized as lumpy. The east-coast weather, a hurricane in the Northeast and these customer changes made for an especially lumpy quarter in terms of revenue. That said, we continue to see strong demand and pricing for our Pressure Pumping services and we are continuing with our program of adding fracturing capacity. Our greatest opportunity in the Pressure Pumping continues to be high sustained utilization. Although revenue met our expectations despite the flooding, operating income from this segment was relatively flat as a result of operational inefficiencies associated with the interruption of operations, product cost increases and higher depreciation expense. As Doug will describe in greater detail, from our perspective, we had another very successful quarter as measured by continued revenue growth in both of our core businesses and strong profit contributions from both. For both drilling and Pressure Pumping, we expect to see further substantial increases in revenue in the fourth quarter. In drilling, we also see opportunities for cost decreases going forward, and in Pressure Pumping, we expect that our costs will not be impacted by as many one-off events. I would now like to turn the call over to Doug, who will discuss our operations for the quarter.

Thank you, Mark. Let me start this morning with some commentary on the drilling company before I'd turn and make some comments on Pressure Pumping. First, the drilling company. For the quarter ended September 30, 2011, the company had an average of 221 drilling rigs operating, including 209 rigs in the U.S. and 12 rigs in Canada. This was a 10-rig increase in the U.S. over the average activity levels we experienced in the second quarter. The Canadian rig count increased to 12 rigs in the third quarter as breakup ended and the industry got back to work. Canadian revenues increased by some $21 million sequentially. As mentioned earlier, the rig count continued to increase in October. Despite some recent weakness in commodity prices, we continue to see strong demand for our rigs. For the fourth quarter, we are now expecting to average approximate 220 rigs in the U.S. and 12 rigs in Canada. Obviously, the fourth quarter gets impacted somewhat by the holiday season. The third quarter was once again highlighted by improvements in activity, continued term contract growth, as well as new-build contract signings with strategic customers. Average revenues per operating day for the third quarter were $21,440, a sequential improvement of $440 per day. Rig pricing continued to improve during the quarter. As Mark mentioned earlier, for the first time in many, many quarters, we had some challenges on the cost side, where average direct operating costs per day increased to $12,980 for the quarter. The 2 areas where costs escalated the most were labor-related costs and repair and maintenance costs in the U.S. Labor-related costs accounted for roughly $400 per day of the increase. This overall increase was attributable primarily to 3 different factors, all of which are impacted by greater oil field activity. Firstly, we experienced higher wages, which was passed through to our customers and reflected in our average revenue per operating day, but we also incurred additional labor costs as we train additional people to meet the demands for activating both new and existing rigs and to respond to overall shortages of skilled oilfield workers. We also experienced increased workers' compensation costs during the quarter. These costs are based on actuarial calculations and are impacted by the higher wages we are currently paying. Our repair and supply costs increased sequentially by some $500 per day in the U.S. These higher costs were related to a variety of items, including improvements to allow some of our conventional rigs to continue to operate at the high utilization levels we have witnessed and to perform efficiently in the current market. Additionally, our costs were impacted from the startup of additional conventional rigs as well as general oilfield inflation. For Q4, we now anticipate that a roughly equal increase in revenues and decrease in costs will improve our average margin per day by approximately $500. With respect to term contracts, I'm pleased to say we had another solid quarter by signing 18 term contracts. This includes 7 additional new builds, 8 existing Apex rigs and 3 contracts for conventional rigs. Based on contracts currently in place, we now expect to have an average of 124 rigs working under term contract during the fourth quarter of 2011 and approximately 96 rigs for 2012. Of course, these numbers do not reflect any renewals or new contracts that we may enter into. As Mark mentioned earlier for added visibility, we're pleased to report that our revenue backlog on long-term contracts in the drilling business is approximately $1.7 billion. Now let me spend a few minutes giving you a quick recap of our new build program for the quarter. In terms of the new build schedule, the 7 rigs we completed worked approximately 220 days during the quarter. Of the 7 rigs, 3 were Apex Walking Rigs and 4 were Apex 1500s. Four of the 7 were deployed in the Eagle Ford, 2 in the Rockies and one in the Appalachians. For the year-to-date, we have now completed 18 rigs and expect to complete an additional 7 during Q4, bringing our total for the year to 25. In addition, as we have announced previously, we also expect to build 30 new builds in 2012. All of our 2011 new builds are under long-term contracts and we're pretty much sold out of new rigs through the first quarter of 2012. Although the pace of new build signings have slowed somewhat recently, this is not uncommon in the fourth quarter, as many of our customers are in the process of finalizing their 2012 drilling budgets. We are currently in discussions with a number of different customers and expect further new build commitments. I'd like to make a few comments on our announcement regarding the retirement of 22 rigs this quarter. We determined that 21 of these rigs would no longer be marketed and they have been retired. Certain of the components of these rigs will be transferred to parts inventory and will be used to support our remaining fleet of conventional rigs. Of the 21 rigs, 18 were low horsepower, i.e. 750-horsepower or less, and all were conventional rigs. One additional rig has been written off due to a fire which destroyed the rig. This rig was a 1500-horsepower mechanical rig. The impact of these retirements on our earnings for the quarter as mentioned earlier was approximately $4.3 million pretax or $0.02 per share on an after-tax basis. That concludes my remarks on drilling, so now let me turn and talk for a few moments about our Pressure Pumping business. Revenues in the Pressure Pumping business totaled $225 million for the quarter. We were on track for a very strong quarter, until Hurricane Irene and the ongoing flooding hit the Northeast market. We feel that these events caused us to lose approximately $10 million of revenue during the quarter. Despite this, demand for equipment and pricing remains strong in this segment, and EBITDA for Pressure Pumping totaled $71 million for the quarter, up some 6% from the prior quarter. Let me make a few comments on each of the operating regions, starting with the Southwest market. We continue to be extremely pleased with the operational and financial performance from this segment. Activity levels remain very strong, particularly in the Permian and South Texas areas, where again we experienced record quarters in revenue. In terms of pricing, our overall frac discounts during the quarter improved by almost 4 percentage points in the Southwest region. During the quarter, we took delivery and deployed an additional 40,000-horsepower in mid-September, and all of this horsepower was deployed in the Permian market. This additional equipment contributed approximately $3 million in the revenue during the quarter. Turning to our Northeast region, after a record-setting quarter for revenue and profitability in Q2, our Q3 performance was disappointing. Revenues declined by approximately 2.5% sequentially, as the weather and location delays drastically cut into our utilization for the quarter. Unfortunately, our labor costs continued as we chose not to release our experienced hands. The demand for skilled labor in this market remains extremely tight, and these delays and shutdowns proved to be very costly in the short term. In mid-August, we added 36,250-horsepower into this market, and the new crew completed some 5 wells and contributed approximately $6 million in incremental revenue. Despite some of the challenges we faced in the third quarter, we still believe that the Marcellus and Utica shales continue to be a bright spot for us in the Pressure Pumping business. Long term, we are very optimistic about the future of this region. I'm pleased to say that the month of October has returned to far more normal levels of activities. On an overall basis, we have approximately 30% of our frac horsepower covered by long-term contracts. We still see ongoing demand for incremental pumping services well into 2012 and are currently in discussions with several customers for additional committed crews. The Pressure Pumping industry continues to face tightness in labor markets, as well as the challenges of sourcing sand, water, acid and other materials to meet the needs of these evermore service-intensive jobs. So before I turn the call back to Mark, let me make a comment or 2 on our expectations for the Pressure Pumping business for the fourth quarter. As we've said previously, we expect to end 2011 with approximately 650,000-horsepower, which includes some 65,000-horsepower to be activated in the latter part of the fourth quarter. However, we expect this additional equipment to be added in the fourth quarter will not generate significant revenue until 2012. We currently have some 140,000-horsepower on order for delivery in 2012. We plan to continue to grow this business in a prudent manner. With respect to the fourth quarter in the Pressure Pumping business, we are now expecting a sequential increase in revenue of approximately 10% and an increase in gross margin to approximately 35%. We anticipate the normal holiday disruptions to impact our business somewhat in Q4. So with that, I'll now turn the call back to Mark for some concluding remarks.

Thanks, Doug. As I hope our shareholders know, we manage this company for the long term, and we have made huge strides in transforming the company. We are proud of the transformation in our equipment fleets, our focus on customer service and our investment in our people. We believe that these investments have transformed our company into a top-tier service provider and resulted in greater demand for our services in the current environment of increasing well complexity. We know that we can still improve and we will continue to take steps to improve in all areas. As I said, we were very pleased with the revenue growth in the quarter and indeed for the year. In fact, for the first 9 months of 2011, our revenues are almost double what they were in the previous year. Although we were disappointed in our costs in this past quarter, we are very cognizant that our earnings increased by more than 270% for the first 9 months of this year. During the last 4 quarters, including our acquisition, our businesses have added 25 new rigs to the Drilling business, approximately 350,000-horsepower to the Pressure Pumping business, and in conjunction with the addition of these assets, 2,000 additional employees. This growth has been managed smoothly with very few hiccups. Before closing, I want to note that the $1.7 billion backlog from term contracts, plus our strong balance sheet, gives me great comfort. The strength of our sector makes me wonder if the current economic concerns are, at least in the case of North American energy market, substantially exaggerated. In closing this morning, I'm 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 December 30, 2011 to holders of record as of December 15, 2011. And last, but certainly not least, we'd like to take this opportunity to thank the men and women of Patterson-UTI. We know that you work in all kinds of weather conditions, some in daylight, others at night all across America. Please know how much we, the board and management, salute you for making this company one that we can all be proud of. You make this company very strong. Operator, with that, we'll turn it over to questions.

[Operator Instructions] Your first question comes from the line of Ivan Solomont [ph] from Dahlman Rose. James Crandell - Dahlman Rose & Company, LLC, Research Division: This is Jim Crandell. Doug, we've been hearing a fair amount of anecdotal evidence of oil companies getting price concessions in the Marcellus on Pressure Pumping, and I think even Halliburton said that Pressure Pumping prices were moving a bit lower there. Given that 70% of your fleet is on the spot market, what are you seeing in terms of pricing today in that market? And do you expect -- and if it is some modest weakness, what are your expectations there in the coming months?

Jim, to be quite honest with you, we have not seen any real price pressure in that market. Now I think prices have moved pretty dramatically over the last year in that market, but we certainly to this point haven't seen really any decrease in the pricing levels that we're witnessing, particularly in Marcellus. James Crandell - Dahlman Rose & Company, LLC, Research Division: And your expectation going forward, Doug, is that would continue, you're not looking for...?

No, Jim, I think it depends on [ph] how much additional equipment continues to move into that marketplace. I do think that the -- if the talk in the industry about the success of the Utica is anywhere near as important as we think it could be, I think we will see -- continue to see pressure, both demand for equipment and improving prices in that market. James Crandell - Dahlman Rose & Company, LLC, Research Division: Okay. Secondly, Doug, your comment about, I guess a slowing of opportunities to bid on rigs, do you see that as being entirely seasonal at this point and entirely associated with the budget cycle of the major oil companies? And is your expectation that once we get through this that we'll continue to see the Permian and Eagle Ford and other sort of oil- or liquid-rich plays continuing to move up at the pace that they've been moving up over the past year?

Jim, I apologize if we left you the impression that it's a slowing in the number of bids. I think that probably is untrue. We've actually seen a little bit of slowing in contract signings, but there's a number of bid situations and customer interests that we're currently working on. So I do attribute it mostly to the current situation with people finalizing their budgets. There's lots of people talking to us about new rigs, and it's not uncommon in the fourth quarter that until they get their budgets signed that they don't commit at this point. We've gone back and looked at the last couple of years and have seen a very similar trend in the fourth quarter, and surprisingly, as soon as their budget seems to get finalized for the year, then we see a kind of a flurry of activity of contract signings. So we're anticipating that that will happen again. James Crandell - Dahlman Rose & Company, LLC, Research Division: Okay. And last question, Doug, could you review, I think I missed this number, on the amount of frac horsepower you're planning to add and the timing of such adds in 2012?

Right. Jim, just so you know, there's about 65,500-horsepower coming at the end of the fourth quarter. We don't think it will have a whole lot of impact on the fourth quarter's revenues. And then we have approximately another 140,000 ordered for 2012. James Crandell - Dahlman Rose & Company, LLC, Research Division: Okay. And is your expectation that that would come in the first half of the year, Doug?

Yes. At the moment, all of those deliveries are really scheduled through the first part of July. James Crandell - Dahlman Rose & Company, LLC, Research Division: Okay. If you were to decide fairly soon to add more, when are we talking about? Fourth quarter of next year, if you did make that decision?

Yes. I think if you placed orders within the next 60 days, you're still looking at late third quarter, probably early fourth quarter unless the supply chain changes dramatically. James Crandell - Dahlman Rose & Company, LLC, Research Division: And is that something under active review at the current time?

Well, Jim, we're in the process. In the next month or so, we will be looking at our capital budgets for the year. We do look at this every quarter. We said -- I think there's a lot of things going on in the marketplace today. We will prudently look at adding capacity and growing this business when we see the right opportunities.

Your next question comes from the line of Joe Hill from Tudor, Pickering. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Gentlemen, just some thoughts around the Marcellus and obviously the noise that was just discussed around pricing, et cetera, contract coverage at 30%, discussions with customers for additional work, committed fleets. Are you willing to take that number up to, say, 50%, and do you think you could do that over the course of 2012?

Jim, if we could get the right kind of contracts, we would probably be prepared to go up higher than 50%, but I think as you've heard us say before, contracts in this business are a little bit harder to come by than the Drilling business. We're certainly open to moving that number higher. I do fully expect that we will have some of our additional equipment signed up and under contract, but we really don't have a number in mind.

I think, Jim, the one thing I would just add is that we're pretty -- we're, I think, very picky about the kind of contracts we want to sign in Pressure Pumping, and Joe, I think the thought we've got is that it's easier for people sometimes to announce contracts. I want to make sure that, for us at least, that our contracts are ones that give us adequate guaranteed kind of revenue, not just in effect a price agreement. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And Mark, on the last down cycle, I thought the land rig contracts held up pretty well for the industry. If you were going to compare a Pressure Pumping contract to a land rig contract at this point, what are the notable differences?

Well, the most important difference, I think, is that a contract for, in effect, a usage of a rig guarantees you 365 days of utilization, and sets in effect a guaranteed margin. Typically, contracts in Pressure Pumping, the ones that we're the least interested in are the ones where they're just setting a price and there are no guarantees of in effect utilization. The ones that we are interested in, there are certain kinds of minimum guaranteed utilization in revenue. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And then just switching gears real quickly. For John, can you give us some indication as to how much of the daily operating cost is labor roughly versus other components?

That was about $500 a day increase. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: That was the increase, but I'm talking about the absolute number.

Labor runs around -- labor and related runs about 65% or so of daily costs.

Your next question comes from the line of Marshall Adkins from Raymond James. J. Marshall Adkins - Raymond James & Associates, Inc., Research Division: Doug, I want to get into the cost increases in a little more detail. You gave us a good overview there of labor versus repair, but it seemed like a lot of those repair costs were kind of one-time costs or one-time upgrade costs as you're bringing the older rigs out of the weeds. Is that accurate, and should we expect that to continue if you're not activating more?

Marshall, I think you kind of hit the nail on the head. I wouldn't attribute it all to that, but quite honestly, if you look over the last 12 months, we've activated a lot of conventional rigs. And what we really found this quarter in our regular process of our supervisors, particularly kind of corporate and head office supervisors getting out, we found a couple of situations and in a couple of geographic areas that we weren't happy with the standards of the rigs, and we jumped on that very quickly as part of a planned process. There's no question that we've spent a lot of money in a very short period of time and had very few operating days to amortize those costs over. I do expect that some of those costs are going to bleed over slightly into Q4, but I do think over time, it was somewhat abnormal. So I think you're very correct in your assumption. I wouldn't say that's entirely all of it, but certainly we do expect over the next couple of quarters those costs to get back to more normal levels. J. Marshall Adkins - Raymond James & Associates, Inc., Research Division: Okay. So along those lines, you got, I guess, for the press release about 350 total rigs in the fleet, and we're looking at 230-plus kind of running. Of the remaining rigs, 100-plus rigs, how many of those haven't worked in the last year? And do you expect to be bringing those out or should we kind of look at more write-downs, or I guess, I would assume probably a combination of both?

Marshall, I'm going to turn that over to John because I think he's got some facts and figures on that segment of the fleet that he can probably give us.

Marshall, with respect to the U.S. fleet, the Canadian rigs, as you know, there's the seasonal ups and downs. Relative to the U.S. rigs, there's, I believe it's about 113 rigs that aren't currently working. And of those rigs, the vast majority didn't work in the last 12 months. Almost all of them worked in 2008, about 100 of them would have worked in 2008. As I think you know, you've covered the company for quite a long time, we continue to retain those rigs looking for opportunities to make money with them as we did in 2008. We'll continue to do that, but as time passes, if the rigs don't go to work, sometimes we use the parts to support other rigs, and if a given rig reaches the point where it doesn't make sense to market it, we retire it. So for example, if the gas markets improve as they were in 2008, I would expect we would run a meaningful number of those rigs. In the current environment, we don't have visibility to run 110, but as Doug mentioned, we've activated a meaningful number of those conventional rigs over the last 12 months. J. Marshall Adkins - Raymond James & Associates, Inc., Research Division: All right, that's helpful. All right, last part of this question is, you gave us good guidance in terms of margins improving next quarter. It sounds like most of that is you're keeping your cost structure or hope to keep it flat from here and revenues or day rates are going to continue to drift higher. Is that the correct read-through?

Yes, I think that's pretty correct, Marshall. We've -- like I say, we think we're going to get higher revenues and we're going to work our utmost on getting our costs down. We've given you our best estimates of what we think that's going to be in Q4, but -- as you know, we don't look beyond that, but I do expect that you'll see margins continue to improve.

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

Just kind of a follow-on question regarding the repair and maintenance expense, I just wanted to know -- the portion that wasn't related to kind of the reactivation, how do these costs compare to some of your newer Apex rigs, meaning that, given the type of drilling that's going on, are the older rigs having to run harder and therefore more susceptible to wear and tear versus a new rig? Are you finding more costs with keeping those competitive?

Dave, for the quarter and for the quarter before that, second quarter, the repair and maintenance and supply costs to Apex versus conventional rigs is not significantly different, but relative to the third quarter, there was a much bigger increase in repair and maintenance costs for conventional rigs for the reasons that Doug mentioned. As time passes and those normalize, they are probably actually a little bit less than the Apex rigs, but back to your question, the repair and maintenance cost is not significantly different for the newer rigs versus the conventional rigs.

Great, thanks, John for that. And then just kind of -- just another question. So we delivered 7 rigs during the quarter, and then there's your recount that you've added close to 20 since the beginning of the third quarter, and most of those adds being in South Texas and West Texas. And Mark, as you alluded to, those are from your conventional fleet, did any of those come with contracts, and then are you seeing the ability to add a few more rigs here -- in those areas in the future, some more of these conventional rigs? It sounds like from your guidance for fourth quarter rig count that it might be a 2012 type of event, if that's the case?

I mentioned during my kind of prepared remarks that of the contracts during the quarter, at least 3 of them were conventional rigs that were being activated. There was an additional 8, I believe, that were sort of Apex rigs that had been working in primarily South Texas and places like the Haynesville that were renewed, contracts that had rolled over and got renewed, but certainly we're still seeing interest in people picking up existing conventional rigs and signing a term contract.

Okay. And so the takeaway there, Doug, is that we could probably see some more increases from the conventional fleet going forward. I mean, can you ballpark? Is it 20 or so or is it something less than that or more than that?

I'd just be guessing if I gave you -- but if you look at the last 3 or 4 quarters we've had, we've had contracts on conventional rigs every quarter for the last 3 or 4, and I just expect that to continue.

Your next question comes from the line of Luke Lemoine from Capital One Southcoast.

Doug, you mentioned the revenue impact in the Marcellus on pumping was about $10 million to Irene, but what was the margin impact there?

I don't have that number at my fingertips, but it's -- John, is it...?

Probably a percentage point. I don't have it here either.

Maybe we can get back to you with that number, Luke.

Okay. And then during the quarter, did you mobilize any horsepower from one region to another?

Not particularly. Most of the horsepower that got added was all new add capacity. In the previous quarter, we had moved some equipment from the Barnett to South Texas, but other than a pump or 2, there really wasn't much changing from market to market.

Okay. And then I guess, John, lastly, could you help us out maybe with G&A, D&A, CapEx for 4Q?

In terms of depreciation, depletion and impairment, my guess would be about $116 million for the fourth quarter. G&A got some [indiscernible] benefits in the quarter, I think it'll move back up in the fourth quarter something more similar to the run rate in Q2, and so I would guess somewhere about $17 million. Tax rate in the fourth quarter I would expect to be about 37.5% for the quarter, and from a CapEx perspective, that would, I suspect, be about $250 million.

Your next question comes from the line of Geoff Kieburtz from Weeden & Co. Chris Enright - Weeden & Co., LP, Research Division: This is Chris Enright in for Geoff. Quick question on the rig retirements. What was the catalyst for the rig retirements? I mean, what changed from 3 months ago? And maybe how these rigs different than the -- differ from the 100-plus rigs that are currently now working?

This is John. Let me try to answer that and then maybe Doug may want to supplement it. We have acquired an awful lot of rigs over the period, particularly 1995 to 2005. As the rig markets change, we adjust the fleet. We've added a substantial number of new rigs. And we're endlessly evaluating how rigs are suited to the marketplace and their condition. So if you go back to, I think it was fourth quarter 2006, we, I think retired 40 rigs that particular quarter. Last year, I think there were about half a dozen. That wasn't a particularly big year for that. This year it's 21 related to our evaluation of the rigs. This is a constant process. The point in time at which they feel that a rig in any given location is best to become parts, and those parts are very useful because we don't have to buy new parts for another rig that's operating. We retire them at that point in time. So I don't think there's any change in thinking. I think it's a consistent approach that's been in place for more than 5 years. Something to add to that, Doug?

First, I'd like to say, we, over the last couple of years we're forever as we have an engine blow up or a driver explodes up [ph] or something. Rather than sort of repairing it right away, we can look around and see what else we have, and over time, some of these rigs get to the point that you say "You know, to put that rig back out, we'd have to incur probably more money than we'd be prepared to and we look at them in terms of, are they safe, could they run efficiently?" So as John said, it's just part of an ongoing process that we go through all the time and evaluating them and looking at whether they should be marketed or not. Chris Enright - Weeden & Co., LP, Research Division: Okay. It sounds like it's partly a function of the success you've had putting conventional rigs back to work in addition to the functionality of the rig.

That would be true. Chris Enright - Weeden & Co., LP, Research Division: Non-related follow-up. If we just turn to Pressure Pumping margins, your guidance for the fourth quarter suggests that gross margin is not quite going to get back to what it was in 2Q. Just kind of wondering if you could give any color on that. Is that solely seasonality creeping up maybe in the Northeast in 4Q, or is there anything else going on there?

I think it's probably twofold. Certainly, we always seem to get some seasonality issues in the Northeast, but I would say that we're under severe pressure at the moment with things like sand pricing, acid pricing, and we sometimes cannot pass those costs through immediately. We do get to pass them through, but sometimes there's a delay from the time that we get those increases until the time we can actually collect for them. So I think that's probably the 2 biggest things in our direction on the guidance. Chris Enright - Weeden & Co., LP, Research Division: Okay, great. And would you expect as those ultimately get passed through, would you expect enough uplift to margins in '12?

I don't -- I think -- let me answer that a different way. I think we will see an uplift in margins. I'm not sure it's going to come from the pass-through of a cost. I think we'll see increase in utilization has more impact on our margins than the cost impact.

Your next question comes from the line of Andrea Sharkey from Gabelli & Company. Andrea Sharkey - Gabelli & Company, Inc.: Just maybe sort of a strategic question. Given recent deal activity, Superior Energy acquiring or merging with Complete Production, do you look at that maybe changing the dynamics, the competitive dynamics at all in the industry, and does it make you start to think about maybe getting into other product lines like coiled tubing or downhole tools, things like that, or are you pretty happy with the growth that you've done with your 2 different business lines?

We're always evaluating businesses to see whether we think that they would really add to the overall portfolio for Patterson-UTI, and we're always considering businesses that are in effect in the same oilfield services or related services that we think would be something that would make sense for us. So the answer to the question is: always considering it and trying to think about it strategically. As for whether we think about it differently when our competitors do things, we try to figure out what everybody's doing in the industry and try to figure out whether someone has a good idea, and if they do, then to sort of see if we can do it. But frankly, one of the things that really has, I think, characterized this management over the past, almost what, 16, 17 years that we've been doing it, is that we've been very much value buyers. And so we're always looking very carefully at what does the opportunity present for us and what's the cost of it, and we're typically very sensitive to that last point. Andrea Sharkey - Gabelli & Company, Inc.: Right. Absolutely that makes sense. And then I just noticed on the revenue per job on the Pressure Pumping business was down sequentially, was that just mix shift, or is something going on there, different regions, maybe more South Texas or Permian than Marcellus Shale, things like that?

Andrea, it's probably twofold, the answer to that question. One, we mentioned the disruptions and the delays that we faced in the Northeast, and those were all big, big frac jobs, horizontal fracs. And what little work we were able to replace it with tends to be sort of the one-day jobs, so you see a shift in that on a per-day basis there. The second part of that is we have a much higher percentage of our horsepower now in the Permian, which also tends to be smaller jobs, high, high utilization, but the jobs themselves tend to be a little bit smaller. Quite often those crews are out in the morning and back to the camp at night. So I wouldn't read anything into that. I think that was just an abnormality during the quarter. I think the long-term trend is no doubt continued longer laterals, bigger jobs. I think it was really just those 2 things that probably impacted those numbers for the quarter. Andrea Sharkey - Gabelli & Company, Inc.: Okay, great. That's what I'd like to hear. And then, I guess just last question for me and I'll turn it back over. I know you guys are in the process of doing your budgeting and everything, but if I think about CapEx for next year, you're planning to build about 5 more rigs than this year, maybe less Pressure Pumping capacity, maybe the same. Is $900 million to $1 billion CapEx for next year sort of reasonable?

Yes.

Your next question comes from the line of John Daniel from Simmons & Company. John M. Daniel - Simmons & Company International, Research Division: Just 2 questions. First, John, I missed the depreciation guidance for Q4.

I'm estimating about $116 million for the fourth quarter. John M. Daniel - Simmons & Company International, Research Division: Okay. And then, as we look at next year, I mean, it looks like you guys will spend close to -- depreciation's ballpark, $90 million increase in '11 versus '10. Should we expect a similar or greater build in depreciation for '12?

Frankly, John, I'm not focused on that number yet. We're in our budgeting process. Your approach sounds... John M. Daniel - Simmons & Company International, Research Division: We're spending more money, right?

I have not calculated it. I would take roughly $1 billion of CapEx and layer [ph] it in just as you would, but frankly, I have not done that yet. John M. Daniel - Simmons & Company International, Research Division: Okay, fair enough. I'll just -- the other question on Pressure Pumping. Of the cost structure today, how much are you able to pass through as the costs rise, and what's the lag? And are you seeing more difficulties passing those increases through?

John, labor, we've always sort of been able to negotiate with our customers and get a pass-through. Most of the contracts have some clauses that cover major materials like sand and acid and various of those things. There can be sometimes a 30- to 60-, 90-day delay while you negotiate these with your customers. It's not as clear-cut as the drilling contracts that specify right in the contract that it's an absolute given. These tend to be much more of a negotiation. And so far, I think the industry has been very understanding of the cost increases, particularly with labor. I really don't anticipate that that's going to change. John M. Daniel - Simmons & Company International, Research Division: Well just really quickly. The Drilling business saw the impact of the higher repair costs this quarter, and presumably, I mean, that's just obviously a function of running the stuff really hard. I mean, the same thing's happening to Pumping right now, you've got a new fleet. If you look to next year, I mean, is it reasonable to assume that that starts to eat away too at margins, all else being equal?

John, I can't disagree with your assumption. I think it's too early for us to call that. We certainly are watching those, things like fluid ends [ph]. We watch those very carefully to see what kind of useful life we get out of those things. There's no question we're running engines and transmissions and all of the equipment. We're running it harder than we ever have, but we're also probably accruing more costs than we ever have. So it's a little bit of a guesstimate on our part, but there's no question that we think the costs are going up, but we are trying to take that into consideration all along the way.

Your next question comes from the line of Mike Breard from Hodges Capital.

Just out of curiosity. I don't know if you can answer this or not, but how many of your old rigs are working on jobs where the customer just doesn't need the advantages of the Apex rig, and what percentage might be working on jobs where the customer has just not been able to get an Apex rig because of shortage?

I guess I had never thought of it that way. I would suggest that I'm going to come at it a little different way. Most of the rigs that are probably working in the Permian today probably are the types of rigs that the customer doesn't necessarily want all of the features of an Apex rig, but having said that, over the last 12 months, we've seen more and more customers in that market go to horizontal drilling and do see the advantages of the types of features that you see on an Apex rig. But I couldn't give you an exact number. But if we had 50 rigs working in West Texas today, I'd say probably 40 of them are rigs where the customer doesn't really necessarily need a top drive, doesn't really care if it has all the bells and whistles.

Your next question from the line of Kurt Hallead from RBC Capital Markets.

I missed most of this call here because I was on one ahead of yours, but just want to get a general sense. Your margins came in, in the quarter, mentioned a number of different variables involved here. If I'm repeating the question, I apologize, but how would you characterize some of these cost issues? Would you view them as completely transitory, partially transitory or structural in nature? And do we need to readjust our sights on margin progression from this point forward?

Kurt, I think we've covered that from several angles, but let me try to summarize. As we mentioned in the prepared remarks, we see margins going up $500 in the fourth quarter, and that's about half from pricing improvements and half from cost savings. During the third quarter, there was a lot of work done particularly on conventional rigs related to repair and maintenance items which also impacted supplies to bring rigs up to the standards, the increasing standards frankly that we expect for our drilling rigs. So I think our belief as we go farther down the road is that those costs will not be as high looking out, but we do believe there is some impact in the fourth quarter also as they continue to finish up that process of getting everything in good order as they see it. Do you want to add to that, Doug? [ph]

No. That's a good answer.

Sir, there are no further questions at this time.

Well, I'd like to thank everybody for their participation in the call. Look forward to speaking with you on our next call. Thank you.

Ladies and gentlemen, that concludes today's call. You may now disconnect and have a great day.