Patterson-UTI Energy, Inc. (PTEN) Q4 2012 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2012 Patterson-UTI Energy Inc. Earnings Conference Call. My name is Erin, and I will be your coordinator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I will now turn the presentation over to your host for today's conference, Mr. Mike Drickamer, Director of Investor Relations. Please proceed, sir.

Thank you, Erin. Good morning, and on behalf of Patterson-UTI Energy, I'd like to welcome you to today's conference call to discuss the results for the 3 and 12 months ended December 31, 2012. Participating in today's call will be Mark Siegel, Chairman; Andy Hendricks, Chief Executive Officer; and John Vollmer, Chief Financial Officer. Again, just a quick reminder that statements made in this conference call that state the company's or management's plans, intentions, beliefs, expectations or predictions for the future are forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995, the Securities Act of 1933 and the Securities Exchange Act of 1934. These forward-looking statements are subject to risks and uncertainties disclosed in the company's annual report on Form 10-K and other filings with the SEC. These risks and uncertainties could cause the company's actual results to differ materially from those that -- suggested in such forward-looking statements what the company expects. The company undertakes no obligation to publicly update or revise any forward-looking statement. The company's SEC filings may be obtained by contacting the company or the SEC and are available through the company's website and through the SEC's EDGAR system. 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?

Thanks, Mike. Good morning, and welcome to Patterson-UTI's conference call for the fourth quarter of 2012. We are pleased you are able to join us today. As is customary, I will start by briefly reviewing the financial results for the quarter ended December 31, and then I will turn the call over to Andy Hendricks, who will share some detailed comments on each segment's operational highlights as well as our outlook. After Andy's comments, I will provide some closing remarks before turning the call over for questions. For the fourth quarter, as set forth in our earnings press release issued this morning, we reported net income of $58.9 million or $0.40 per share for the quarter ended December 31, 2012, and $299 million or $1.96 per share for the 12 months ended December 31. EBITDA was $233 million for the quarter and more than $1 billion for the year and represented our highest annual EBITDA since 2006. These results for the fourth quarter are better than many people expected, we included. So let me point out that there were no extraordinary or unique gains during the quarter. Both of our core operating businesses performed better than expected, especially pressure pumping, where we saw greater-than-expected activity levels. I believe our strong performance during the quarter in pressure pumping, which included awards of incremental work from existing customers, arose from our company's core focus on customer satisfaction and the relationship we have with our customers. To meet this increased activity level, we began commissioning our idle pressure pumping equipment. Additionally, our pressure pumping margins benefited from a higher-than-expected level of efficiency as the work lined up such that we are able to spend a greater amount of time under 24-hour operations and working on multi-well pads. Our fourth quarter results demonstrate the continuing earnings power of our pressure pumping business. During the fourth quarter, we repurchased 3.4 million shares of our common stock for approximately $60 million. Since the beginning of the second quarter of this year, we have invested approximately $170 million, repurchasing a total of 10.7 million shares of our common stock or almost 7% of the outstanding shares. The share repurchases in 2000 allowed us to return capital to shareholders during a period of low share prices. The $170 million of share purchases were purchased at an average price of less than $16, which is an average valuation of less than 3x actual 2012 EBITDA. We expect capital spending for 2013 of approximately $680 million, down from $974 million in 2012. Included in our budget for 2013 is the construction of 13 new Apex rigs, including 8 that are deferred from 2012. One of the benefits we receive by controlling our own manufacturing effort is flexibility. We demonstrated our ability to scale our manufacturing efforts to meet market demand as we reduced our 2012 new Apex program to 22 rigs from our initial plan of 30 rigs. While our current 2013 plan calls for a reduced build program, we are capable of scaling the number of rigs either higher or lower depending upon demand for newbuild rigs. We expect our cash flow from operations to fully fund our 2013 CapEx budget and to provide free cash flow. We will continue to look for opportunities to profitably grow the company, and we have demonstrated our willingness to return capital to our shareholders. Since 2005, we have returned over $1.1 billion to shareholders, including share repurchases totaling approximately $770 million. We have demonstrated ourselves to be good stewards of capital. With that, I'll turn the call over to Andy.

Thanks, Mark. I'm going to deviate from our typical conference call format and discuss pressure pumping first, as this business accounted for the majority of our better-than-expected results. During the fourth quarter, our pressure pumping business benefited from an increasing level of activity and greater efficiencies related to both a greater amount of 24-hour work as well as more work on multi-well pads. Sequentially, our pressure pumping revenues increased 16% to $212 million and our gross margin improved by approximately 170 basis points to 30.7%. This was a great quarter for our pressure pumping business. For the year, I'm pleased that, despite the increasingly challenging market conditions during 2012, the EBITDA contribution from this business of $244 million fell by only 9% from 2011. In the fourth quarter, we saw a higher level of activity as customers performed well completions that had been delayed from previous quarters. And additionally, we experienced a much lower level of seasonality related to holidays than we had in recent years. The increased level of activity combined favorably with our work schedules to reduce the amount of downtime between the jobs. Additionally, a greater amount of 24-hour work and more work on multi-well pads combined to positively impact our efficiency, thereby also positively impacting our profitability. Going forward, we expect activity levels to show modest improvement. While I'm not sure that we can say that demand has improved across the industry, demand has improved for our services. The higher activity levels we experienced in the fourth quarter required us to begin commissioning the new equipment that we had taken delivery of earlier in 2012. Initially, we did not activate this equipment as we waited for demand to improve. And let me be clear, we did not stack any working horsepower in 2012. This was new equipment and not a reactivation. And additionally, to meet our higher activity levels, as well as for our preventive maintenance program requirements at the high levels of utilization for both 24-hour operations and the multi-well pads, we purchased an additional 13,500 horsepower at an opportune time in the market. The equipment we have been activating is primarily to meet incremental work awarded to us by our existing customers. It's an important distinction to note that we were not aggressively bidding this equipment, which would've negatively impacted the market. But we did respond as opportunity arose to activate this horsepower, all at reasonably profitable pricing levels. As evidenced by the fact that we were awarded this work, I believe our customers see value in the high-quality service that we were able to provide. We truly are a leader in reliable and efficient pressure pumping services in the markets in which we operate. You may have seen the article on our pressure pumping business, Universal, where one of the spreads we are activating for a customer in the northeast is being converted to have dual fuel capabilities. The engines on these pumps will be able to burn a fuel mix comprised of up to 70% natural gas. We've been working on this technology for a year now, and we're proud to be on the forefront, as it's not only good for the environmental sustainability, but it also offers lower operating costs through reduced fuel charges. We ended 2012 with approximately 750,000 horsepower in our fleet. We are continuing to activate horsepower and expect the remainder of our idle equipment to be activated by the end of the first quarter. With respect to the first quarter, we expect our pressure pumping activity levels will increase further as we continue to activate equipment. We expect this higher activity will increase pressure pumping revenues by approximately $20 million from the fourth quarter, while our gross margin percent is expected to soften to around 27.5%. As a result, we expect EBITDA from our pressure pumping business to be relatively flat quarter-over-quarter. We believe that market pricing is close to a bottom. Our overall pricing is expected to be slightly lower on average than the first quarter. Additionally, we expect to incur some personnel training costs associated with the activation of our equipment. Finally, we do not expect to be able to achieve the same level of customer efficiency in the first quarter, as work on multi-well pads in our schedule is expected to be a little more spotty and weather in the northeast may negatively impact our ability to efficiently move people and equipment to and from the job sites. For 2013, CapEx for pressure pumping is expected to be approximately 20% of our total 2013 CapEx budget, the majority of which is related to maintenance CapEx as well as spending for natural gas conversions and facilities. No additional fraction horsepower is budgeted for 2013. Turning now to contract drilling. Our contract drilling continues to be our largest business, with revenues accounting for almost 2/3 of our total revenues. Revenues from contract drilling decreased 5% sequentially to $425 million as our U.S. activity levels slowed in the fourth quarter. During the fourth quarter, we averaged 198 rigs, down from 211 in the third quarter, but this was better than expected. In Canada, we averaged 7 rigs, up from 5 rigs in the third quarter. Average revenue per day in the fourth quarter was relatively unchanged at $22,460 as a greater contribution from Canada offset a slight decrease in the U.S. Pricing held relatively firm during the fourth quarter with the slight decrease in average U.S. revenue per day partially attributable to a greater number of rigs on standby under reduced rates. Average direct operating costs per day were similarly impacted by an increased contribution from Canada, and as a result, increased by $110 per day to $13,450. Accordingly, our average margin per day was better than expected, with a decrease of only $90 during the fourth quarter to $9,020. Looking forward, we are still encouraged by our outlook for 2013 drilling activity. Our own rig count dipped in January, averaging 197 rigs, including 187 rigs in the U.S. and 10 rigs in Canada. This dip was primarily related to several rigs that were on standby rolling off contract. We currently have 4 rigs on standby. For the first quarter, we expect our rig count to average 200 rigs, including 190 rigs in the U.S. and 10 rigs in Canada. We expect average revenue per day will increase $600 during the first quarter due to a combination of factors including fewer rigs earning lower standby rates, a greater proportion of our higher dayrate Apex rigs and more rigs in Canada. The fewer rigs on standby and more rigs in Canada are expected to result in an increase of $500 in direct operating cost per day. As a result of the increase in average revenue per day, average margin per day is expected to increase $100 during the first quarter. In terms of our newbuild program, we completed 6 new Apex rigs during the fourth quarter, including 1 Apex Walking Rig and 4 Apex 1500 rigs with a walking system feature. As Mark mentioned, our 2013 capital budget provides for 13 new Apex rigs, including 8 that were deferred from 2012. We expect that many of the new Apex rigs we build in 2013 will have walking systems as an added feature. CapEx associated with contract drilling represents approximately 3/4 of our total 2013 CapEx budget. In addition to maintenance CapEx and the 13 new Apex rigs, we plan to continue enhancing some of our existing Apex rigs by adding walking system capabilities for pad drilling. We had 47 Apex Walking Rigs in our fleet as of December 31, as well as another 13 Apex rigs that had walking systems. As I mentioned on our previous conference call, we have developed a walking system that can be added to any rig in our fleet, giving the rig full multidirectional walking capability. Customer interest in these walking systems has been strong, as our Apex 1500 and Apex 1000 rigs with this walking system can still be moved quickly between pads while having the increased flexibility of a multidirectional walking system. The value of the flexibility offered by our walking rig pad drilling system will become increasingly apparent as customers continue their transition to development mode and return to existing pads, where perhaps only 1 or 2 wells will drill the whole of the acreage. Other so-called pad drilling rigs may not have the capability to move over or around these existing wellheads or other obstructions on the pads or may not have the capability, be it horsepower, hook load or setback capacity, to drill many of the longer laterals that are becoming more prevalent. I am encouraged that, as we continue to enhance our existing fleet of Apex rigs with pad drilling walking capabilities, we will further our leadership position with pad drilling. Our total term contract backlog as of December 31 totaled $1.24 billion. Based on contracts currently in place, we expect to average 97 rigs under term contract in 2013, including 123 rigs during the first quarter. While we are not prepared to speak to the second quarter in any detail, please let me remind you that the Canadian rig count in the second quarter will be impacted by the seasonal breakup. Before I turn the call back to Mark for his concluding remarks, let me provide an update on a couple of other corporate financial matters. We currently expect SG&A to be approximately $17 million in the first quarter. Depreciation expense for 2013 is expected to be $540 million, including $134 million in the first quarter. Our effective tax rate for the first quarter is expected to be approximately 36%. With that, I will now turn the call back to Mark.

Thanks, Andy. 2012, as a whole, was a year with notable achievements despite considerable challenges in the market. During 2012, as customers reacted to low natural gas prices, we efficiently repositioned rigs from dry gas basins to oil and liquids-rich markets and minimized lost revenue days. And as the slowdown in drilling activity became broader-based, demand for our high-specification Apex rigs remained strong. This strong demand for our Apex rigs allowed us to maintain high levels of utilization on our Apex rig fleet while also building an additional 22 Apex rigs during the year. Compared with prior periods of weakness in drilling rig demand, the contrast this time is stark. Our share of the market basically stayed strong despite all of the changes in 2012. Moreover, we remain convinced that our upgraded fleet of non-Apex rigs, manned by our well-trained crews, provides efficient, cost-effective drilling for many customers. We believe that this capability for a certain type of efficiency is widely underestimated by the investment community. Furthermore, our customers' recognition of the improving quality of our overall rig fleet helped us to maintain a strong rig count despite the decrease in overall rig count during the second half of 2012. In pressure pumping, I'm proud we are able to keep all of our active spreads running profitably, with full year 2012 EBITDA from this business of $244 million despite a challenging market. We initially chose not to activate a substantial portion of the new equipment that was ordered in 2011 but not delivered until 2012. Ultimately, our customers awarded us sufficient work that required us to begin activating this equipment in the fourth quarter. I believe that these operational achievements during 2012 result from our core focus on customer satisfaction. I would like to both commend and thank the hard-working men and women who make up this company, as it was their focus on the customer that helped to differentiate us during these challenging market conditions. The operational achievements during 2012 were complemented by financial achievements. Let me tell you a few of them. We sold our non-core flow back operations and generated approximately $47.5 million of cash. We issued $300 million of aggregate principal amount of 4.27% fixed-rate notes with no scheduled principal payments until maturity in 2022. And we refinanced our credit agreement, which both increased our revolving line of credit by $100 million to $500 million and provided for a $100 million 5-year term loan. With this, our liquidity improved to $571 million at December 31, including $111 million of cash and $460 million of availability under our revolving line of credit. Our successful operations and financial strength enabled us to return more than $200 million of capital to shareholders through share repurchases and dividends. As we progress into 2013, we continue to be well positioned. Our focus on high-quality service delivery will keep us strongly aligned with our customers to continue to increase their focus on operational efficiency in both pressure pumping and in drilling. With that, 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 March 29, 2013, to holders of record as of March 15, 2013. Operator, we would now like to open the call for questions.

[Operator Instructions] Your first question comes from the line of Ryan Fitzgibbon with Global Hunter Securities.

First one, on the pressure pumping margins during the quarter, I'm trying to understand -- no, I understand you're doing more paddy work, more 24-hour ops. Can you quantify what the base point impact there may have been on the quarter? And then the sequential decline of about 300 basis points in Q1, should we think of that as mobilizations of this activated equipment from the East Texas yard going up to Marcellus?

No, I wouldn't look at it that way. As we worked our way through the fourth quarter, the seasonality that we've traditionally had just didn't appear. And we were requested by customers to actually do more work on pads and increase the percentage of 24-hour work that we were doing. And that's kind of how things played out as we worked through the fourth quarter. What we see going into the first quarter, as we just discussed, is we'll see some -- a little bit more spottiness in the way the pads line up. We're still doing some 24-hour activity. We see increasing activity because of the extra horsepower and crews that we've activated, but not quite the customer level of efficiency in lining up the work as we saw in Q4.

I'd just add, additionally, we also have some costs of activating the equipment that we're going to be bearing in this first quarter.

Okay. And then would it be your expectation that Q1 would, in theory, mark the trough for margins, as that equipment's up and working in Q2 and beyond?

Historically, we've only spoken to this next quarter, so that's pretty much as far as our crystal ball allows us to gaze. There's been a lot of talk about pressure pumping pricing. We're definitely among those who are hopeful that it's bottomed out, but I think anybody trying to call a bottom in a market in which there's been this supply of equipment's challenged.

Fair enough. And then in Q4, how much of the 100,000 horsepower that was vital or stacked was actually activated during the quarter?

So we had almost 100,000 horsepower that we had. It wasn't stacked, because stacked implied that it was working. We never stacked any of the crews in 2012, and we always saw that as a positive sign. Our crews are doing a great job for the customers out in the field, and we never had to stack anything. We did receive equipment in 2012 that was ordered in 2011. This was almost 100,000 horsepower. Approximately half of that equipment began its activation in the fourth quarter. The other half -- and went to work. The other half began activation towards the end of the fourth quarter and will start work in the first quarter of 2013.

And can you disclose where that worked in Q4? Was that Permian, Eagle Ford, or did you send some to the Marcellus as well?

I think it's safe to say that it's pretty well-balanced across all our operations.

Fair enough. And then last one for me with the, call it $50 million left on the buyback, do you have plans to, I guess, re-up that again for 2012? Then, where your stock price is now, what's your thought process on either buying back more stock, increasing the dividend or adding additional rigs on top of what you've already disclosed for the '13? I mean, would you consider a...

Ryan, you, I think, just accurately described the things that our board takes into account each quarter; namely, what are the capital demands for the business so that we can invest properly to have for our shareholders and customers the right equipment, the right amount, balanced between trying to make sure that we have an adequate supply but not to have an oversupply. So that's the first decision. And then to the extent to which there's free cash, then to think about whether to return it to the shareholders in the form of dividends or buybacks. Last year, obviously, with what we thought was a very significantly underpriced stock, which we commented on a couple of different times in these quarterly calls, we thought it was a very opportune time to deploy the extra cash that we found ourselves with, or the extra capital we found ourselves with, in the form of a repurchase. We continue to look at that. As you noted in your question, there still is $50 million -- over $50 million left of authorization. We feel that if the board thinks that, if there were a good opportunity to rebuy -- repurchase stock, then they would consider the possibility of increasing that. But at this point, we're kind of having a -- take a look at this year and try to see how it unfolds and try to get a real perspective on varying and taking into account both stock price, capital needs and all kinds of other circumstances.

Your next question coming from the line of Marshall Adkins with Raymond James. J. Marshall Adkins - Raymond James & Associates, Inc., Research Division: You gave us pretty good color on the pressure pumping. Just a couple little ones, though, just to get a little more clarification. How much of this stark contrast in your performance versus most of your peers was geography, specifically the Marcellus? Or was it a specific customer? This is just such an anomaly versus what we're hearing everywhere else. Is there -- and we've got the pad drilling and all that stuff, but is there something else that we're missing there?

That's a good question. We work in the northeast. We work across multiple basins in Texas. What we saw was really a bit of a broad base within our customer basket. What I said earlier was that these are existing customers that had increases in activity. It wasn't one specific customer, but it was our existing customers that had some increasing activity that we were able to respond to. J. Marshall Adkins - Raymond James & Associates, Inc., Research Division: And the tone is, it does seem repeatable, obviously, within the confines of margins maybe getting dinged a little bit as you roll out some of this new equipment, but fairly repeatable.

Marshall, I'd say that we are, in both our market areas, roughly, Texas and the northeast -- I think we've become very well received as a Tier 1 service provider in that business, and as a Tier 1 service provider, and perhaps even a provider of choice, I think our customers are very satisfied with our service and looking for us to do more work for them. And I think that, that's what's allowing us to, a, generate increased activity at good margins. And I've talked a bunch about execution, but I think that we, Andy and I and the rest of the team here, just need to thank the people in those businesses, because the execution they're providing is what's winning us the business. J. Marshall Adkins - Raymond James & Associates, Inc., Research Division: Well, they're doing something right. Second question for me, on the U.S. land side, you have these other 13 Apex rigs come online. You're putting a lot more walking systems on these rigs. Give me some sense of what bidding out there for the newer rigs is looking like right now? Are we sensing any kind of upturn given the fact that it seems like things kind of hit a lull period there towards the end of the year?

What we're seeing so far on the pricing on drilling -- and you see in our results that our average revenue per day on drilling is holding relatively steady. And looking at the pricing, we're seeing that hold relatively steady as well. We didn't see that for our fleet come down in Q4, and we're seeing it hold relatively steady going forward in Q1. J. Marshall Adkins - Raymond James & Associates, Inc., Research Division: I guess I'm thinking more just bidding activity. Is there a lot of interest still in the newer rigs?

Frankly, Marshall, it's one of those things where, and this has been, I think, something that surprised the management team here, it's kind of a -- it's either a large number of people contacting us or, in effect, a quite period, and it kind of vacillates between those 2 things. And so in any given day, if you ask us what's happening, it would depend very much on the particulars of the time period. And we've gone through periods where it's been pretty active and other periods where it's been less active. So quite frankly, I'd say right now, we're feeling pretty good about it. We're starting to see some pickup in activity in terms of people's interest in rigs. Frankly, you're more of an observer of this than just about anybody, but the high oil prices are obviously, I think, spurring people to think about [indiscernible]...

Just to add to that, when we look at the CapEx budget and the newbuild plan for 2013, we're looking at building right now 13 new rigs. With the moving parts and the additions of the walking systems that have been requested in Q1, we'll build 3 rigs in Q1. And those 3 rigs are already under contract.

And your next question comes from the line of Robin Shoemaker from Citi.

I just wanted to pick up on that last comment you were making. Some of the major service companies have said they believe, based on their customer -- discussions with customers, that the rig count will increase by 100 to 150 rigs sometime between the beginning and the middle of this year. Does that kind of conform with what you believe? Based in the Marcellus, Eagle Ford, Permian, Bakken, where you're working, do you see that kind of increase or more or less?

Robin, we've heard the predictions about 2013 being about flat with 2012. And as you realized, obviously, the '12 was a year in which we were strongest in the first half and weaker in the second half. In order for us to see that kind of similar numbers for, in effect, 2013, we'd have to see an uptick from where we've been currently. So that prediction is one which we have heard. If you listen to our prior calls, we really basically thought that we were going to start to see that kind of increase in activity right about now, kind of end of fourth quarter, beginning of first quarter. Frankly, it's been a little slower in terms of coming back up. And the numbers we've given you for our [indiscernible] quarter are a little weaker than I think we would have guessed for, in effect, drilling for the year. But quite frankly, I think we're very optimistic about the future periods, because we do think that, that prediction that you gave -- I don't want us to put a -- I don't want to, in effect, accept the numbers specifically, but the idea that we're going to see an uptick in drilling is something which we felt pretty strongly about as well.

Okay. On the pressure pumping side, then. Just wanted to understand the very significant increase in average revenue per job as your total jobs fell sequentially. So does this reflect the 24-hour, more 24-hour work that you were -- or change in the size of jobs that you're executing? And just how would you explain that big increase in average revenue per job?

So that's a good question. And the way we've traditionally counted jobs actually had some variability in the number of frac stages per job. And as we went into 24-hour mode, we were getting more stages per day, obviously. And so that's had an impact on that number.

Okay, so that's it. Now just finally, one, you've talked about your CapEx. Do you have a total CapEx budget for this year that you can share with us? I didn't -- if you said, I didn't hear it.

Yes. In fact, I did say it was $680 million for 2013.

And your next question comes from the line of Kurt Hallead from RBC Capital Markets.

So a question I had for you specifically was if you look at the exit rate in the first quarter on frac, given the incremental equipment that you're putting to work, what kind of revenue run rate should we be looking at as you exit the first quarter? You mentioned $20 million in total increase on revenue, but that won't be really fully indicative of what your run rate's going to be when you exit the first quarter. So what are we looking at as an exit rate first quarter?

Yes. I'm not sure we're ready to guide what the exit rate of the first quarter is, but when I talked about the activation in the new equipment and I said half of it was activated in Q4 and the other half began its activation and commissioning at the end of Q4 and doesn't get fully up and running until Q1, so you do see a bit of an increase there in the run rate.

Right, but you pretty much have a handle on what that exit rate's going to be at the end of March, though, right?

A lot of it has to do with how the customers line up the pads and things like that. And that's where we saw the shift from Q4 into Q1.

Okay. And then the margin -- so when we think about, again, we think this through, and you go through some initial period of inefficiency and activating equipment and getting people on the location and getting them trained and all that other stuff that seems to happen, obviously, the first quarter margin is going to be soft [ph] relative to what the true run rate would be. So is it true run rate, on a go-forward basis once you get everything running, looking more like the fourth quarter?

I think the answer to the question, Kurt, goes like this. There was a number -- and I'm not trying to not answer the question, but I think the problem is that the answer to the question is a complicated one. So you have a number of factors, one of which has been, in effect, we have some pricing agreements in sentence [ph] that are rolling off. And so there's some impact of going from the contract price to, in effect, a market price. Now I want to make it very clear that we think that there's a premium price for premium service, and as a Tier 1 service provider, we think that, that we're not getting the lowest price in the market. We're getting a fair price in the market going forward on non-contracted work. So one issue, frankly, is what's the price. Second issue is, in effect, the training cost that you made reference to just a moment ago and the startup cost that we were talking about that you also referenced. So that's the second one. And then the third issue that has a dramatic effect on margins is, in effect, how efficient we're able to be. And that's not really controlled by us, because the degree to which our customer set up pads where we have the opportunity to do a large number of stages on 1 day or 24 hours or whatever the, in effect, metric that we're going to be using is, that all has an effect. So the last piece is what we have in prior calls sometimes described as lumpiness or lack of lumpiness, and that's a factor that affects kind of both what the margin and the revenue will be. And that's why you're getting a -- we don't -- we're not ready to pin a specific tail on that number and say to you exactly what it will be exiting first quarter.

So let me -- and in that context, what percentage of your frac fleet will be coming off term contract during the course of the fourth quarter and repricing in the first quarter?

I think there's one customer that the contract expires in the first quarter, but I don't have that specifically in front of me.

Yes.

Okay. And then just putting a broader perspective, if we look back historically at your margin progression here on frac going back a number of years, you're not below 30% gross margins for -- you're really not below 30% margins for any extended period of time. So that's more of an observation than a question. On the land front, you just mentioned you have 3 rigs that are coming up and going to contract in the first quarter. So you have 13 that you're bringing in, including the 8 that you kind of pushed into this year from last year. What's the contractual status of those other rigs?

So that's still in progress. Like I said, we expect to deliver 3 rigs in the first quarter, and we're still optimistic with our build plan, especially our Apex 1500 horsepower, because utilization for that class of rig is still running around 90%.

And your next question comes from the line of Byron Pope from Tudor, Pickering. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: I kind of like a little bit of the 2013 CapEx that's allocated to the land drilling business will be for walking systems. And I know, Andy, you'd talked about the capability to retrofit existing SCR and mechanical rigs with those walking systems. Could you just speak to kind of the incremental demand you're seeing there to retrofit some of your existing rigs with the walking systems? Kind of where, regionally, you're seeing that incremental demand?

Yes, that's a good question, Byron. We're really excited about the walking systems, and it's -- there's been a lot of interest from the customers. We anticipate that many of these 13 rigs that we build in 2013 will have the walking systems. I don't actually have our CapEx broken out to tell you exactly what that number is. I can let you know that on the maintenance side, we're still running around $100 million. And we have the new rigs and the upgrades for the systems at around $400 million. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And then -- and just wanted to ask, again on the drilling side, just what you're sensing in the Permian? And it seems as though activity there has been a little more sluggish than we would've thought, just given where crude oil prices are. So given your strong market presence in the Permian, I'm just curious as to the nature of the conversations you're having with your drilling customers out in that basin?

We're certainly encouraged by where the level of the commodity prices are trading and the range that they're in right now. And the Permian always has the ability to turn back on quickly. I think we have some customers right now that are evaluating the new play, trying to understand the verticals versus the horizontals and production and reservoir scenarios on that. But we're certainly encouraged going forward there. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: So is it fair to think you guys will incrementally be able to deploy some of your newbuild Apex rigs into the Permian on horizontal work?

We have that potential, yes.

And your next question comes from the line of Brad Handler from Jefferies & Company. Brad Handler - Jefferies & Company, Inc., Research Division: Well, the conversation about hydraulic fracturing is interesting, so maybe I'll keep us on that side. So I think you answered a fairly specific question from Kurt with respect to what was rolling off sort of -- or what had just rolled off in terms of contract coverage. But more broadly, what is your contract coverage currently within the pumping side?

So currently, out of the total horsepower, which is 750,000 roughly, we have about 155,000 horsepower which is under term contract coverage. And one of those contracts will roll off and has already been renegotiated in the first quarter. With the changes -- I'm anticipating your next question is going to be what does that mean for us? We see our average pricing on pressure coming down just a little bit in Q1, and it's one of the reasons we're reluctant to call a bottom. There's still a lot of equipment sitting on the sidelines, but what's been encouraging for us is, with the customers that we have today, they keep stats on our performance and the performance of the others that they're using, and we had an opportunity to take more work for those customers, and we did. Brad Handler - Jefferies & Company, Inc., Research Division: I understand, and I definitely want to come back to that in a second. Just by the end of the year, how much currently would be under term contract?

I don't think we have that number with us.

No. Brad Handler - Jefferies & Company, Inc., Research Division: Okay. Is it safe to think some other contracts probably also roll, so that you're subject to market pricing to some degree on what is reoccurring [ph] later?

Yes, we likely have 1 more contract that we'll roll before the end of 2013. Brad Handler - Jefferies & Company, Inc., Research Division: Okay. So if I take that idea, but extend it forward, so your customers -- it seems like it's a great signal when your customers are telling you, "Do more work for us" and giving you a fair price for it. To what degree or -- is the conversation include some more contractual commitments, terming up in some way or another? But what sort of visibility are you getting about sustainability from contract discussion?

Well, listen, we wouldn't have activated the new equipment if we didn't have long-term work for this new equipment. The pricing agreements we have with these customers include a work plan that we see keeping this equipment busy going forward, or we wouldn't have activated it. There's still a lot of equipment on the sideline. It's still a challenging market. I think we'll work through some of that as we go through 2013 as an industry, but we've still got a ways to go. Brad Handler - Jefferies & Company, Inc., Research Division: Understand. But you're not calling it 100,000 horsepower of additional term commitment. So you're not telling me it's 155,000 goes to 255,000?

No.

No. Brad Handler - Jefferies & Company, Inc., Research Division: A difference sort of relationship, I guess?

It's like our other contracts, where we have a pricing agreement, we have an understood scope of work, we understand what the customer wants to do in terms of well count, volumes per month, things like that. And that's how we come to this conclusion on these contracts and the decision to activate the new equipment. Brad Handler - Jefferies & Company, Inc., Research Division: Got it, okay. That certainly makes -- that makes sense. And is it your general sense that the additional work falls in line with a lot of 24-hour and a lot of pad drilling-related? Is it -- is that an extension of some of what you saw in the fourth quarter?

We certainly had an increase in 24-hour operations in Q4 and -- which increased our efficiency. We will see an increasing amount of 24 slightly going into Q1. But also at the same time, there are some gaps between pads as we do some of these 24-hour operations, if that makes sense. Brad Handler - Jefferies & Company, Inc., Research Division: Sure, sure. There's more 24-hour jobs in total, perhaps, but not as stacked, not stacked as well.

Yes. Towards the end of Q4, they all got stacked close together.

And your next question comes from the line of Andrea Sharkey from Gabelli. Andrea Sharkey - Gabelli & Company, Inc.: So just kind of thinking about 2013 across both of your businesses, drilling and pressure pumping. Is there anything that we should be thinking about or that concerns you in terms of cost inflation, whether it be labor or raw materials, things like that, that maybe we should just be keeping an eye out for?

If I look at 2013 versus 2012, we started off with a much higher activity at the beginning of 2012 and kind of entered that soft patch towards the end of the year. So as we start to increase activity in 2013 based on flat capital spending in the industry year-on-year, we'll see our activity level come up a bit. But I don't think it's enough of a ramp to actually cause us labor inflation or real cost inflation that's material. Andrea Sharkey - Gabelli & Company, Inc.: Okay, great, that's helpful. And then maybe just more of a higher-level question for you, Andy. Now since you've been CEO for a while, has there been anything along the way that has surprised you, both positively and negatively? And looking forward, I guess, what's still on the plate for you that you think needs to get done?

I appreciate that question. Certainly, when we look at the rig technology on the Apex rigs that we're building, that's really exciting with the fast-moving 1500 and the utilization that we're seeing in that class of rig. But one thing I'd like to really point out is the quality of the people that we have here is just fantastic. And it's not just the people that run our businesses in the regions around North America, but it's the people that are executing the services at the well site. And you saw their ability in Q4 to ramp up over a short period of time to handle increased levels of activity for our customers, and they did a good job. Andrea Sharkey - Gabelli & Company, Inc.: Great, that's helpful. And then, I guess, last one for me is just the whole shift towards equipment that can run on natural gas that seems to be gaining a little bit more traction. You guys are converting a pressure pumping spread. How many more do think that you have planned to do in the near term on pressure pumping? And then can you also do the same thing on your drilling rigs, and are there plans to do that? And then maybe even another question on that is, can you kind of help us a little bit with the economics of it from both your perspective, how much does it cost to do that, and then who gets to share in the cost benefit? Kind of split that with your customers, or do you pass it all along to them? How does that work?

So the conversions for natural gas have actually been going on for a while, but they've been increasing in momentum. We have drilling rigs that, in the past, have been able to work on natural gas. But it really depends on the availability of the fuel in the area that you're working, in a specific area, not just region or basin, but are you close to infrastructure to get natural gas to your job site. So we've had rigs for a while that could do that. We will see drilling rigs going forward, where we ordered more systems for natural gas. And on pressure pumping, we started testing the natural gas bi-fuel engines last year. We had good results with the horsepower outputs, and the equipment was working well. And we were able to deploy our first full frac spread with complete bi-fuel conversion here in early 2013. So we're very excited about that. On the economic front, there's certainly a huge savings for -- on the fuel cost for the industry. What we're able to do, our customers share in that, and they get that benefit. So we are able to work that into our pricing.

And your next question comes from the line of Mike Urban from Deutsche Bank.

Wanted to come back and talk about the pressure pumping market a little bit. Again, I think you guys did a good job of going through a lot of the details. And I think you've addressed this a little bit, but I wanted to get a little more specific in terms of the criteria that you've looked at for -- I guess reactivating isn't the right word. Commissioning some of the equipment that you took delivery of. Clearly, there was a hurdle you weren't reaching previously because you took delivery and put it in the yard. Is it a margin threshold or return threshold? Is it the fact that the customer has demand for it and somebody else will do it if we don't, and we think we can get that utilization up? I mean, I'm just trying to get a sense for the analysis that might go into that.

Sure. It's a number of factors, and you hit a number of them in the way you posed the question. I think the first thing we would say was, we saw a market that was oversupplied by -- with equipment. And so having made this order in 2011 and had delivery in 2012, the thing we didn't see any need to do was to simply flood the market with additional equipment and in effect be another one of the low-priced bidders who is, in effect, trying to get work at any price. And some of that, as you know, has been bid at prices that's barely breakeven. That wasn't something that was of any interest to us. So what we saw was that we would, in effect, put it behind a locked gate and listen until we saw a situation where we felt there was continued work, ideally from the kinds of customers that we'd had good experience with before, that was going to be on a long term, expected long-term basis under profitable conditions, consistent with the profitability we were achieving with our other equipment. And we if felt that, in effect, that was possible, then we were willing to, in effect, take that work out from behind the locked gate and put it to work. But it needed to have those qualities of, in effect, continued work on a profitable basis for reliable customers. And those were the things that I think generated and caused us to want to put that work, that equipment to work. Andy, you want to add anything to that?

That's exactly right. We've talked about this before. We've gotten this question several times over the last 6 months or so, and we just didn't see any need to push this equipment out there when there was already so much on the sidelines unless we had a compelling reason to do that and have a profitable business with this equipment. And with some of the customers that we had, they had some plans to increase their levels of activity and our crews were able to step up and do that, and we were able to work out terms that make sense for this equipment.

So it sounds like you don't feel like the margins on the incremental equipment you've deployed are materially different from what the rest of the fleet was getting?

We would agree with that statement 100%. We don't think the margins are materially different on the new equipment from the existing equipment.

That's correct.

Okay, great. And then just a clarification, the -- I think you said 13,500-horsepower that -- you acquired that? Was that an open, in the secondary market?

That was a purchase of new equipment right at the end of the fourth quarter.

Okay, okay. And that was -- was that taken -- took delivery from a manufacturer that you'd already placed the order, or was that acquired from somebody else?

That was an order that we placed at the end of the fourth quarter from one of our -- a company that is a manufacturer and supplier consistent with equipment that we have in the field.

And your next question comes from the line of John Daniel from Simmons & Company. John M. Daniel - Simmons & Company International, Research Division: I guess, Andy, how many of your frac fleets currently allow customers the self-sourcing option for raw materials such as sand and chemicals, and how many customers are taking that option today?

That's a good question. We do have some that source their own sand. Offhand, I'm not sure what percentage that would be, and it really kind of also depends on basin. We might work for a customer that would do it for themselves in one basin but not in another. So I don't have that in front of me. John M. Daniel - Simmons & Company International, Research Division: Okay. But would you attribute any of the utilization gains to the -- to what you do in terms of your offering that option to customers?

No, no. Not -- in the results that you saw in the fourth quarter, it didn't have anything to do with that. John M. Daniel - Simmons & Company International, Research Division: Okay. You noted 20% of the CapEx budget will be directed towards pumping, but no new horsepower would be added. Can you walk us through where that money is going to be spent?

Yes, sure. So for instance, there's always the maintenance CapEx, and that's the biggest portion of pressure pumping CapEx, typically. Last year, if we look at it, it was running around $50 million. If you consider the fact that we've added almost another 100,000 horsepower to what we call active operations and we're increasing slightly the percentage of 24-hour work, that number will move from $50 million, maybe into that $60 million range in 2013. We've also got equipment upgrades on existing fleet, which are the data-logging units that we have on locations. We've got upgrade kits for the natural gas engines that we continue to order as we anticipate customers will want to make some switches there. And we've got some facilities upgrades. John M. Daniel - Simmons & Company International, Research Division: Okay. When you have spend, call it $60 million on the maintenance, roughly how many of the pumps will be rebuilt?

So maintenance is a continual process. I suspect every pump in the fleet at some point is going to get some maintenance on it. And that's -- and the preventative maintenance program that I mentioned earlier, it's what's important and it's what gives us the reliability and the uptime that we need to have that high level of efficiency and service quality for the customer. So you're seeing the payback of the investment in preventive maintenance by increased levels of activity. John M. Daniel - Simmons & Company International, Research Division: Okay, all right. Last one for me, and I hate to keep beating on margins like everyone else, but just is it safe to say, Mark, that when you look at the equipment that's being deployed now, the new equipment, that the margins at the fleet level are higher than the overall segment margins?

I'm not sure I understand the question. John M. Daniel - Simmons & Company International, Research Division: So your -- okay, gross margins. You guided to 27.5% for Q1. So in theory the fleet -- at the fleet level, because the gross margins incorporate a certain level of overhead, that those incremental fleets that are going to work, that their gross margins would be in excess of the segment margin? Therefore, it's additive to margins when you get past Q1?

I think it's back to what we said a minute ago. The pricing for the new equipment and fleets that we're activating is consistent. And I think it's safe to say the margins are consistent as well.

And your next question comes from the line of Jason Wangler from Wunderlich [ph] Securities.

Just had one quick one as far as the pressure pumping equipment you picked up. Was that just an opportunistic move, obviously, to step in and get something done? And I know you said that as far as CapEx spend, you wouldn't see much there except maintenance on the pressure pumping side. But would you still be opportunistic, maybe if the market got better, to grow through acquisitions maybe of some depressed sellers?

So just to start off, the equipment. It wasn't necessarily an opportunistic buy. What happened is as we increased the level of activity in Q4 and going forward into 2013, especially with the increase in 24-hour operations on the pads, we just needed a little bit more equipment to be able to circulate in and out of that to manage our preventive maintenance program and maintain that high level of reliability and efficiency that our customers want there. So that was the reason for the purchase for the additional pumps there at the end of the fourth quarter.

With that having been said, we're always looking for opportunities to add value for our shareholders. And if attractive opportunities arose to acquire assets that are in our core businesses, whether it would be drilling or pressure pumping, we'd be interested. So we're always looking for those opportunities. So by all means, we would look for it. But I think as Andy said, that additional 13,500-horsepower that was bought at the end of the year was bought for a particular need that we perceived.

Could I then maybe, just as a follow-up on that, and that's helpful, just did you buy that actually from a manufacturer new again, or was that picked up from somebody who had worked it and was walking away or decided to do something else or whatever?

That was brand new.

And an existing manufacturer.

And your next question comes from the line of Scott Gruber from Bernstein. Scott Gruber - Sanford C. Bernstein & Co., LLC., Research Division: Could you tell us how much you paid for the pumping equipment that you bought at the end of the quarter?

No, I don't think that would be fair. Scott Gruber - Sanford C. Bernstein & Co., LLC., Research Division: Okay, I'll take that as a good price point, then, for you. And most of my other questions have been answered, but in terms of 24-hour ops, what percentage of your fleet is running 24 hours today approximately?

It fluctuates. But as we moved into the fourth quarter, it increased up to, if I look across the board across all of the basins that we're working in, maybe in that 50% range if I average it out, and we'll see a slight increase going into Q1. Scott Gruber - Sanford C. Bernstein & Co., LLC., Research Division: Wow, that's great. Where would you peg that number at, say, 6 months ago? How much of it increased over the course of the latter half of last year?

I don't have that exact number from 6 months ago, but I'd say it's been a fair increase since then.

Yes. I think it's increased. But I don't think we have the number 6 months ago. So I don't think we can give you what the number is.

And your next question comes from the line of Judd Bailey from ISI Group.

Most of my questions have been answered. I just had a follow-up on newbuild rigs. You've indicated 13 for this year. 2 questions. One, what would it take for you to maybe increase that number? Would it just be simply conversations with customers? And if you did see a bigger increase in demand for those Apex rigs, if someone wanted them by the end of the year, could you deliver on them by the fourth quarter? Or would we anticipate those going into the fleet in 2014?

Well, thanks, I appreciate that question. So in the CapEx budget right now, we have 13 rigs. We're working that budget within our projected cash flow for 2013, allowing for some free cash flow as well. We have the ability, because we do our own manufacturing, to ramp up or down as required. Certainly, if the discussions with customers start to increase, then we'll look at that. The other piece is we are spending some of this CapEx on inventory past these 13 rigs, where we are buying a few major components that if we needed to, we could ramp up, if required.

And could you deliver something by the fourth quarter of this year, if that were necessary?

Sure.

Okay. And in terms of labor, would that be a problem at all, or would you feel comfortable with that, as well?

No, we wouldn't have any issue there.

And your next question comes from the line of Tom Curran from Wells Fargo.

It's been a very [indiscernible] Call thus far, so I really only have one left at this point. Returning to the earlier questions on M&A interest and the current pipeline, would it be fair to say that, if we were to see pricing continue to languish around these levels or simply not improve very meaningfully, that you could see some attractive opportunities arise on the pressure pumping side? And then maybe give us an update on the appetite for what it would take, if anything, for you to consider extending outside of pressure pumping into other completion-related offerings?

So let me try to take all those questions. I think there's a couple there. The first, I would say, predicting the M&A activity strikes me as one of those things that's virtually impossible because you never know when sellers decide they want to sell and trying to figure out whether, if they want to sell, then whether the price that they would want to sell for is one which you would find attractive. And so, having done this for a number of years, I have concluded that I, at least personally, have very little ability to predict when those materialize. One always hopes that something will come, will arise, because quite frankly, I think that the acquisitions that Patterson-UTI has executed over its history have been, by and large, very, very beneficial for the shareholder. So my short answer is I hope so, but I couldn't predict it no matter what I try to do. I don't see any basis for making those kinds of predictions. So that's the first question. As to the, "Would you consider going outside of your 2 core businesses," the answer is we'd consider it. But frankly, we think that there's a real benefit in focus on our 2 core businesses. And that's the thing that, if you ask me, one of the things that we're proud of is that we have really got ourselves to a very directed focus in terms of our 2 core businesses. That's where we put our attention into. And I think that focus has really helped us to generate exceptional results.

That's helpful. I guess, on the drilling side, it's been impressive how the big 4 have really remained dominant over the last 3.5 years as the Tier 1 fleet has more than doubled. And as a result, I still have the sense that there's simply not many potential Tier 1 corporate acquisitions out there. Is that still the case, or have we gotten to a point where you're starting to see some new entrants emerge within the Tier 1 niche?

As I look at it, we see a leadership position among a couple of companies, those companies in the business we, I think, all know pretty clearly. And quite frankly, I think that those companies are likely to expand organically in terms of drilling. So I'm not particularly optimistic that there's opportunities in drilling for us, or for anyone for that matter, particularly with regard to the start-ups. But I can't rule it out. I couldn't say for sure, but that's my guess on it.

[Operator Instructions] The next question comes from the line of Trey Cowan from Clarkson.

This is going to sound kind of shotgun scattered, but I have got a couple of different questions. When you -- previous comments on retrofitting your rigs with a dual fuel, it sounded to me like you're saying that those rigs would receive a premium versus a similar rig that isn't dual fuel. Is that a correct assessment?

So we have some newbuilds in progress that are going to have natural gas engines on them. And we adjust the pricing to account for the additional CapEx spend on that.

Got you, okay. And then on the equipment that you disposed of this quarter, was that all drilling equipment?

That was in Q3. Are you referring to the small gain?

Yes, just the small gain there.

Yes. If you look back over time, we have those virtually every quarter. We use a lot of iron. And to the extent that, that iron's no longer usable to us, we cut it up and sell it for scrap. So I think if you look back over the last several years, that's always there, and from our perspective is, frankly, a recurring part of operations primarily related to the drilling business.

Got you. And then another scattered thought. On the frac spread that you guys purchased during the quarter, should I think of that as one frac spread, or should I think of it as incremental to get you to a certain amount of horsepower for a frac spread?

So just to clarify, it wasn't a spread, it was some individual pumps that we needed to work into the preventive maintenance cycle the we have just due to the increased amount of 24-hour activity that we have. When you're working 24 hours, you don't have an opportunity as frequently to pull pumps out and get them back to facility. So we just needed to add a few pumps to the overall fleet to manage that.

Okay, great. And then pulling back to 30,000 feet, I don't think I heard anybody ask this. What's your perspective as far as wells drilled and wells completed in 2013 versus what we saw for 2012 levels?

I think the consensus in the industry is that we're seeing flat spending year-on-year from the operators. And considering the fact that rig count activity worked its way down in 2012, I think we're optimistic that it will work its way up a bit in 2013.

And there are no further questions at this time.

So let me conclude by thanking everyone for their participation on Patterson-UTI's fourth quarter conference call. I look forward to speaking with you again at the end of the first quarter. Thanks, everybody.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Good day.