Patterson-UTI Energy, Inc. (PTEN) Q1 2014 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Quarter One 2014 Patterson-UTI Energy, Inc. Earnings Conference Call. My name is Darren, and I will be your operator for today. [Operator Instructions] As a reminder, this call is being recorded for replay purposes. And now I'd like to turn the call over to Mike Drickamer, Director of Investor Relations. Please, proceed, sir.

Thank you, Darren. 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 months ended March 31, 2014. 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 the 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, as 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 suggested in such forward-looking statements or 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 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 first quarter of 2014. 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 March 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. Turning now to the first quarter. As set forth in our earnings press release issued this morning, we reported net income of $34.8 million, or $0.24 per share. Consolidated revenues for the first quarter were $678 million, and EBITDA was $206 million. Our balance sheet is strong. We exited the first quarter with $258 million of cash and equivalents, and a conservative 13.4% net debt to cap ratio. Contract drilling performed well during the quarter with increases in our average rig count and average revenue per day exceeding our expectations. However, as previously announced, pressure pumping was challenged by the unusually severe weather during the first quarter. Demand is strong for high-spec APEX as we achieved better than 97% utilization of our rig fleet of APEX rigs during the first quarter. In fact, recently demand for newbuild surged further, such that all of the 20 newbuilds for this year are spoken for. Our next newbuild availability is not until 2015. Additionally, demand for our fleet of non-APEX rigs -- demand improved for our fleet of non-APEX electric rigs. In order to meet customers' current rig demand, we continue to activate non-APEX electric rigs during the quarter. Our non-APEX electric rig count increased on average 3 rigs in the fourth quarter and 5 rigs in the first quarter. We have an additional 12 non-APEX electric rigs in the U.S. that could still be activated. With the increase seen in U.S. horizontal rig counts since last summer, we believe that the industry has reached the point where high-spec land rigs are in short supply. Accordingly, we believe that the industry is at a point where in previous cycles, dayrate increases accelerated. With that, I will turn the call over to Andy.

Thanks, Mark. Following our typical format, I'm going to start this morning with some commentary on our drills [ph] business and then finish with some comments on pressure pumping. The appreciable increase in rig demand that first became apparent in the fourth quarter continued through the first quarter. On average, our U.S. rig count increased by 10 rigs to 193 in the first quarter from 183 in the fourth, which was better than we had expected. I'm pleased to report that the rig count continues to grow with the April rig count expected to average 199 rigs. In Canada, our average rig count increased to 10 rigs from 9 in the fourth quarter. Drilling activity in Canada is being impacted by the spring breakup with our average rig count for April expected to be 1 rig. Our average revenue per day increased in the first quarter by $210 to $23,380 from $23,170 in the fourth quarter, excluding the benefit from early termination revenues in the fourth quarter. Average operating cost per day increased $270 during the first quarter to $13,780, primarily due to rig reactivation expenses and also the typical first quarter payroll taxes. The increase in average operating cost per day was largely offset by the higher than expected increase in average revenue per day. Our average margin per day was relatively unchanged and better-than-expected at $9,600 per day in the first quarter when excluding the early termination revenues in the fourth quarter. Looking forward, we expect demand to continue to improve with our average rig count in the U.S. expected to average 201 rigs in the second quarter. Our Canadian rig count is being impacted by the spring breakup and is expected to average around 2 rigs. For the second quarter, we expect our average U.S. margin per day will increase approximately $300 per day. With the changing geographic mix in the second quarter related to the seasonal decrease in Canadian activity, we expect our total second quarter margin per day will increase by approximately $100 to $9,700. Total revenue per day is expected to decrease to $23,100 due to the lower contribution from our higher revenue Canadian rig. This is expected to be more than offset by lower operating cost, which are expected to decrease to approximately $13,400. We completed 3 new APEX rigs during the first quarter bringing our APEX fleet at March 31 to 127 APEX rigs. We contracted an additional 5 new APEX rigs since our last conference call, including 4 to be completed in 2014 and 1 to be completed in 2015. We have seen a surge in demand for new APEX rigs in the recent weeks and are now effectively sold out of newbuilds through 2014. We expect to complete 20 rigs in 2014, and all either have signed contracts or committed and awaiting signature by customers. We will continue to build rigs to meet customer demand for high-spec APEX rigs, and we have added 6 more new APEX rigs in our construction program. We now expect to complete 23 rigs during the 4 quarters ending March 2015. As of March 31, 2014, we had term contracts for drilling rigs providing for approximately $1,040,000,000 of future dayrate drilling revenue. Based on contracts currently in place, we expect to have an average of 137 rigs operating under term contracts during the second quarter and an average of 111 rigs operating under term contracts during the remaining 3 quarters of this year. Turning now to pressure pumping. As previously announced, our Appalachian operations were negatively impacted by unusually severe weather during the first quarter. This resulted in us having crews and equipment on location that were unable to provide revenue-generating services. Furthermore, while on location, we continued to incur labor, demurrage and other costs, including fuel costs to run our equipment in order to protect it in these extraordinary weather conditions. The weather impact in the northeast was partially offset by improvement in the southwest, which benefited from increased activity in the Permian. Accordingly, while pressure pumping revenues of $240 million is still short of our original expectation, revenue still increased sequentially from $234 million in the fourth quarter. With the disruption in the northeast, gross margins as a percent of revenues decreased sequentially to 16.8%. We remain fundamentally positive on the outlook for pressure pumping with the increasing horizontal rig count. Increasing horizontal drilling activity combined with greater frac intensity is leading to higher demand for pressure pumping services particularly in the Permian Basin. While we believe the industry continues to be oversupplied, however, with the increasing demand, the industry is moving toward equilibrium. As a result and given our increasing utilization in our Texas operations, we have ordered sufficient equipment to a rate of 40,000 horsepower frac fleet that can activated towards the end of the year. For the second quarter, we expect pressure pumping revenues will increase sequentially by approximately 10% to $265 million, and gross margins will return to approximately 21% of revenues. We continue to focus on differentiating ourselves in this business through excellent well site execution, the introduction of new technologies, and the investment in new facilities. We believe we are leader in bi-fuel frac technology that uses natural gas as a fuel source. In the Marcellus, we have completed approximately 700 stages using natural gas as a fuel source. As in drilling, we believe that natural gas bi-fuel is an important green technology as it both reduces the environmental impact of our services and generates cost savings with our bi-fuel frac units able to cut diesel fuel consumption in half. Today, our bi-fuel frac units have replaced over 358,000 gallons of diesel with lower cost and cleaner burning natural gas and thereby eliminated approximately 2.6 million pounds of transportation loads on local roads. 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 expect to spend approximately $950 million of CapEx in 2014. We expect our effective tax rate to be approximately 32.7% in 2014. SG&A during the second quarter is expected to be $19 million. Depreciation expense during the second quarter is expected to be $152 million. And with that, I will now turn the call back to Mark for his concluding remarks.

Thanks, Andy. Looking at industry rig data, the horizontal rig counts bottomed last summer and has since increased by more than 150 rigs. Accordingly, we believe substantially all of the high-spec rigs, that were idled in 2012 and 2013 have now returned to work. Looking at our own fleet, our existing APEX fleet is operating at effective full utilization and all of the new APEX rigs we are expecting to complete in 2014 are spoken for. Moreover, based on publicly available data and comments, it appears virtually all of the U.S. industry high-spec rig fleet has taken up with commitments. In our experience, dayrate increases accelerate when the industry reaches this point. And we think we are well positioned to take advantage of the expected increase in pricing, given our rigs in the spot market and 77 rigs rolling off term contracts during the last 3 quarters of this year. With strong commodity prices, and commensurate rig demand, we see a potential benefit in the remainder of year -- of remainder of the year as pricing response to demand. Our overall rig count, both APEX and non-APEX rigs, is likely to increase at a measured pace, given long lead items for new rigs and the usual constraints for idle rigs going back to work. Perhaps most significantly, the strong customer demand continues to provide an impetus for us to continue retooling our fleet, which has substantially transformed our company. Turning to pressure pumping, the industry continues to be oversupplied. We believe, however, that demand for pressure pumping services is likely to continue increasing, driven primarily by the more than 150 rig increase in the horizontal rig count since last summer together with further increases in horizontal activity, horizontal drilling activity and frac intensity. In essence, pressure pumping lags drilling and we believe increases in drilling activity likely will drive future increases in pressure pumping. With this expected increase in demand, we see the industry moving toward equilibrium. There is an additional reason for our optimism. The past year's very harsh and prolonged winter has left natural gas in storage at the lowest level in 11 years. Gas prices reflect this level of storage. These higher natural gas prices provide our customers with increased cash flow and provide the basis for further increases in oil-directed drilling and pressure pumping services. Additionally, to overcome the shortage of gas, we may see increase natural gas drilling and pressure pumping later this year. With that, I would like to both commend and thank the hardworking men and women who make up this company, as it was their focus on the customer that helped to differentiate us. I am also pleased to announce today that the company declared a quarterly cash dividend on its common stock of $0.10 per share to be paid on June 26, 2014, to holders of record as of June 12, 2014. Operator, we would like to now open the call for questions.

[Operator Instructions] Our first question through is from the line of Robin Shoemaker from Citigroup.

Andy, I wanted to ask, in terms of -- you mentioned some upside in pricing for APEX type of rigs. How far are we below prior cycle, maybe peak levels for spot and term contract rates? And would you anticipate that we gradually return to prior peak pricing levels?

That's an interesting question relative to peak, and where -- how far back you'll look to find a peak. I will tell you that our rig rates have remained steady, 3 the last year. It's not that we saw a big dip in 2013. We were holding pricing for APEX, newbuilds or pricing for the renegotiation of contracts and they have been rolling. It all held steady for us all through 2013 and as we entered 2014. Because of that, we're very positive about the business. When it comes to some of the leading edge rates and what that means versus spot and relative to peaks, we don't really want to call out specific information for competitive reasons, but we are very encouraged. We're sold out of newbuilds for 2014. And we believe there is a limited availability of high-spec rigs in the U.S. market, and we believe that the drilling rig rates will continue to improve. If we look at what we said in the margin area, we stated that we're expecting that the U.S. margins are going to increase by $300 per day from the first quarter to the second quarter. And so if this strength continues in the third quarter, given the fact that we're already sold out of the newbuild rigs for 2014, and we can see that strength in the market. And with typical seasonal recovery in Canada, we would expect to even achieve total drilling rig per margin dayrates increased by about $400 per day from Q2 to Q3.

Okay. So that's just a result of the kind of 77 rigs that are coming off contract repricing at slightly better levels. Great. Understood. So I was wondering also if you could speak about the cost pressures you may be experiencing. Of course, what we hear most about are shortages of labor and cost-related challenges in the Permian, where you have a very sizable preference -- presence. So I was wondering if you could talk about that and how you are managing through these cost pressures?

Sure. So that's a good question. There's -- if you are a company that is a Permian-based company trying to operate in the Permian today and you are recruiting in the Permian, you are seeing challenges in trying to get people. If you're a company that works across North America and you have a recruiting effort like we do across North America, then you're less challenged because your focus is you're not just trying to pull people from that Midland-Odessa area. So we recruit people from across the country. And in fact, over the last year, half of the people that we recruited into drilling were active returning military. So we're getting a good population across the U.S., but with half of the individuals being active returning military, we're getting a very high quality of individual coming into the system working for Patterson-UTI. So we're not seeing the same kind of pressures necessarily that you would see if you are a very Permian-focused company that's recruiting strictly in Texas or in West Texas. So we're not seeing those same kind of overall cost pressures that maybe some other companies are, especially when it comes to labor. So like I said, that's why if you look at our margins going from Q1 to Q2 in the U.S., we expect the drilling margins are going to increase by $300 per day because we'll also be able to keep these costs in line. And I also, because we're sold out of the newbuilds for 2014, spoke a little bit about what we might see in Q3 and if we see increase in rig rates further, this could further accelerate third quarter margins as well. They could be even a little bit better because we will be holding our costs in line and we're seeing a very strong market right now.

Robin, the thing I will just add to that answer also is that we're not new to West Texas. The original Patterson comes out of West Texas. We've been a strong business there both on the drilling side and then recently through our acquisition through the pressure pumping business with homegrown businesses that have long and distinguished history there. So for us recruiting in those markets is a little different, I think, than for some of those new players who just entered the market.

Next question is from the line of Byron Pope from Tudor, Pickering, Holt. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just on the drilling side of the business. The constructive pay rate commentary, it sounds as though based on how you're framing the incremental fleet average daily cash margin is that, that will benefit the non-APEX electric rig as well. But is that almost across basins as opposed to just the Permian?

Yes. I'd say it's equally across basins. We've seen rates move up on APEX. We've even seen rates move up on the non-APEX electrics as well. Mechanicals have been holding steady right now, but as activity increases in 2014, we'll see how that level of rig class moves as well. But I'd say that's across basins. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And then on the pressure pumping side, excuse me if I missed this, but the 40,000 horsepower that's being added, will that be bi-fuel capable?

It certainly has the potential to be bi-fuel capable. We also have bi-fuel kits on order, so we'll determine if we need to add those kits to that fleet. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. and given the deployment will be late this year, I'm assuming -- how constructively you're framing the pressure pumping market, it's still up in the year as to whether or not they will be deployed in the southwest as opposed to the northeast?

We're going to be focusing that on the markets in Texas, that's where we're seeing the strongest increase in activities. We're very positive about the business overall. We did state that we believe that it's oversupplied right now. But let's look at the macro, Patterson-UTI drilling has sold out a new APEX rig in 2014. The industry has increased the horizontal rig count by approximately 150 rigs, since the low of 2013. And if you look at the newbuilds in 2014, the industry is putting out about 80 to 100 newbuilds across 2014. So you got increasing horizontal activity, we've got increasing frac intensity, especially in the Permian, where you're moving some from vertical to horizontal. And so this is just going to lead to a steady increase in pressure pumping utilization throughout 2014 and into '15, and this is why we're certainly encouraged to go ahead and order this 40,000 horsepower and we expect that this will be activated sometime around the end of '14.

Next question is from the line of Jason Wangler from Wunderlich Securities.

Curious on the drilling side, you talked a bit, obviously, about gas prices doing better in the inventories and things. Have you started to hear much rumblings as far as just inquiries in the -- to moving something out and some of those less active gas basins or maybe even been able to run some rigs that way? Because I think you mentioned a few rigs you have gotten on the last few months that were non-APEX.

I think you're putting together 2 things. We have seen some -- the increasing activity in our non-APEX rig fleet, so that's one point. And we have also seen a few, but there are very few, inquiries about rigs going to work for natural gas. So we have seen just a little of that. Obviously, we're all conscious of the fact that we're at this very low storage level. We're also at a this very low gas rig level. So one starts to think that, that's a very interesting possibility for later half of the year or into 2015. Not seeing a lot of activity now, but typically customers take a while to react to these sorts of things. We just have the harsh winter kind of continue even into April. And so if you expect that it takes some time for people to respond, we're not really surprised by the fact that they haven't already responded, but think that that's possibly second half of the year event.

Sure. And then, curious on the pressure pumping side, specifically up in Appalachia, obviously the weather was very tough and that's understandable. We've heard in other basins that the tough weather wasn't as harsh on drilling and obviously you guys would know that very well. Is there a big backlog of wells or maybe an inflated backlog of wells that the completion work just wasn't done on, as there was a lot of drilling going on? But like you were saying, the completion just couldn't go off because of the weather. Is that maybe a little bit higher you would expect going into the second quarter or maybe there's going to be some catch-up to be played in that region that may be helpful as we go throughout the year?

Drilling activity stayed relatively busy through the winter season, especially since you've seen this increase in pad drilling over the last few years. We're not having to move rigs as often from pad to pad. But at the same time, I wouldn't say that for us there's a big backlog of wells. I would say that our calendars are starting to fill out and we're certainly encouraged, especially after the harsh weather we saw in Q1 up in the northeast. And so that's why we're saying that our margins are going to be back in that 21% range. But I wouldn't say it's a big backlog, but I would say that the calender is filling out.

The next question is from the line of Marshall Adkins from Raymond James. J. Marshall Adkins - Raymond James & Associates, Inc., Research Division: All right, Mark, you mentioned the Permian, I know you are the dominant position there historically. Help us understand. Do you -- is there a competitive advantage you have being there? And I know you don't think about it in these terms, but what percent of your business is there now and recognizing that most of your assets are on wheels and they actually move? Where do you see that going?

I'll let Andy take the first shot at it.

Is this in reference to drilling or pressure pumping? J. Marshall Adkins - Raymond James & Associates, Inc., Research Division: Yes. Both.

About 25% of our drilling business is in West Texas across the Permian and into New Mexico. Very excited about our position there. We have multiple facilities to support that operation in West Texas. And back to the challenges in people that you might be hearing from some others, we're recruiting nationally to bring people into the Permian. So we're not seeing necessarily -- maybe you said there's some of the challenges to get people crewed up on rigs over there. So we're very encouraged by the increasing activity levels in the Permian. We're encouraged by the increasing rig count, especially around horizontal drilling in the Permian. And that kind of moves on to our pressure pumping story. We're upbeat about this business, we think that utilization will continue to improve steadily throughout the year. And when you look at how we're positioned in West Texas Permian, we have multiple facilities. We are running not just hydraulic fracturing, but cementing and other services across the basin. We have probably one of the most comprehensive lab facilities in West Texas, so that we can do chemistry testing right there in Midland. It doesn't have to go to other places for testing and we do it in house. We're running cementing lab testing 24 hours a day to support our operations there. So when it comes to the Permian, we're in good shape. J. Marshall Adkins - Raymond James & Associates, Inc., Research Division: Lets shift gears a little bit. The rig reactivation, I would guess to be in the Permian may help those, but of those, I think, Mark, you mentioned 10 more additional ones that you -- electric rigs that you could reactivate. What are the prospects for those, number one? Number 2, should we be concerned about the -- as you reactivate the cost that comes into the system, are you kind of already planning for that?

Marshall, the number is 12. And the answer to the question is that, frankly, what will spur us on to activate those rigs is the same thing that spurred us on to activate the ones that we've put out so far, which is that the customer is willing to pay a dayrate that in effect takes into account whatever the costs of reactivation are and gives us terms that we believe will enable us to in effect make a good return on our investment, if we need any. So we're very conscious of that. Frankly, one of the very good things about the upcoming quarters is we have some significant flow of new rigs coming forward in the marketplace next 2 quarters and so we're feeling pretty bullish about that element. J. Marshall Adkins - Raymond James & Associates, Inc., Research Division: Perfect. Last question for me. The 40,000-horsepower you mentioned that you think is enough to get that going. Is that all incremental kind of newbuilds or is that part of what you had before and part new?

No, that will be completely incremental newbuild. Everything that we have today is out working somewhere, so this will be incremental.

Next question is from the line of Waqar Syed.

Given that you already kind of sold out for your newbuilds for the remainder of the year, if you were to choose, could you increase the cadence of the rigs that you can -- newbuild rigs that you can supply to the market in '14?

In '14, that might be a little bit difficult, everything is working off long lead items. It's why we've increased the number of rigs that we're going build going into 2015, so I wouldn't necessarily expect us to increase for '14. However, if you look at the upside and the total number of rigs that we have out working today, we have 137 rigs that are on contract. If you look at it, in Q2, we have about an average of about 64 that are on spot. And what you'll see is opportunities on some of these to move upwards as we progress in 2014 with the increasing rig rates.

Sure. Now what is the main item that's in the -- the lead times are longer? Is it just the top drive or there are other items as well where the queue is long or the wait times are long for ordering?

I would say, top drive is AC-controlled drive systems. But I wouldn't say necessarily that lead times have extended. It's just that they remain steadily long on those bigger items.

Okay. Now in terms of the leading-edge dayrates, you seem to be very positive there. Could you quantify to us kind of a range of increases that you're seeing there?

Well, back to what I was saying earlier for competitive reasons, we don't really want to call out a number or a range. And I'd like to take you back to a discussion around what we see the margin doing. So as we stated, we expect that the margin is going to go up by $300 per day in the U.S. from Q1 to Q2. And if we look forward even to Q3, if you add in Canada, the total drilling margin per day will have an increase of approximately $400 per day. And if the increase in rig rates further accelerates then third quarter margins could even be better.

Great. Now would you hazard a guess to what the total industrywide rig count increase could be by the end of the year from where we stand today, based on what you're seeing or hearing from your customers?

I think it's difficult to actually predict what that total increase is going to look like. Certainly on the new builds, we're seeing about 80 to 100 newbuilds come to the market. What's also been interesting for us at the same time is we've been holding steady on our non-APEX, we're holding steady, we actually increased our non-APEX electric and mechanical rig count. I think there was some concern that as we put out newbuilds that some of these rigs might drop in the count, but that's not been the case. We've actually increased the non-APEX electrics and the mechanicals.

The next question is from the line of John Daniel from Simmons. John M. Daniel - Simmons & Company International, Research Division: Andy, the top line guidance for pressure pumping seems a bit light when you consider that the guidance for Q1 was originally $260 million. And I would assume that the original Q1 guidance is -- at that point had factored in some weather days, just given a view that frac calenders are probably more robust in Q2 than Q1? Can you just comment on why and just some thoughts on the color for the guidance? [indiscernible]

Q1 was a bit challenging with the weather. As we get into Q2, we still had some winter that kind of spilled into April at the same time, but we are starting to fill up the calendars again. The northeast is getting back on its feet, and that's why we're encouraged that the margins will get back to 21%. But we are seeing the calendar start to fill out again. John M. Daniel - Simmons & Company International, Research Division: Okay. In addition to the 40,000 horsepower, is there any other horsepower that is on the order at this point?

No. John M. Daniel - Simmons & Company International, Research Division: Any plans to retire old frac horsepower this year?

No. The horsepower that we have -- and maybe this is in the context of is equipment wearing out or something with reference to that. We're just not seeing that. When you look at a pressure pumping company like ourselves, one of the top tier, and certainly a very well-performing pressure pumping operation, we continue to invest maintenance capital. And you see us manage the M&S [ph] budget around that to where we're continually maintain that equipment. And we're not seeing equipment wear out in that horsepower-class range. If we were to retire any horsepower later in the year, it might be because it's just smaller, older pumps that just aren't capable of horizontal frac-ing, but certainly nothing to do with equipment wearing out. John M. Daniel - Simmons & Company International, Research Division: Okay. Are you -- how often or what's the cycle time from when you rebuild the equipment? 10,000 hours? You have that set time?

It's not a set time on a pump package. You've got different hours on an engine, different hours on a transmission, different hours on the pump. John M. Daniel - Simmons & Company International, Research Division: Okay, fair enough. Last one for -- well, 2 quick ones. One, full year expectations for depreciation if possible? And then second, have you guys updated or published a new price book for your pressure pumping segment yet? And if not, do you intend to do it anytime soon?

John is looking up the depreciation number.

Yes. The current estimate is about $615 million for the year.

When it comes to pricing in pressure pumping, we haven't published a new pricing book. We have been actively trying to push pricing up in Q1. We had a few successes, but in general, I would say it's not moving up overall. I would say it certainly has stabilized and we'll just see how that success continues as we continue to increase utilization as we work through 2014.

The next question is from the line of Jim Wicklund from Crédit Suisse. James Knowlton Wicklund - Crédit Suisse AG, Research Division: Better late than never. Considering the strength that you see in the drilling market today, in an existing rig, not a newbuild, but an existing rig, would you rather have it on contract if it rolled off or keep it on spot?

Bigger terms, it depends on what the pricing is, Jim. I mean... James Knowlton Wicklund - Crédit Suisse AG, Research Division: That's why I'm asking you the question.

The price and the term, Jim. I mean, we're -- as you well know, there is a number of financial people here at Patterson-UTI who spend a lot of time thinking about those exact questions. And we're frankly trying to figure out the rate of incline right now. Frankly, we started the year 2014 thinking that it was going to be a good growth year. We have seen this surge in demand toward the end of -- just toward the beginning, middle of April and we're looking at that and thinking about how to take in -- what it means for the rest of the year. Frankly, it's a little hard to telescope further down the road because just what we've seen now, it looks pretty positive. But we're trying to figure out the rate of increase. James Knowlton Wicklund - Crédit Suisse AG, Research Division: Surge in demand usually puts the focus on the spot market, historically, right?

It does. So as you can imagine, we've got a few operators that are trying to lock us into some long-term contracts and have that optionality for themselves. But for us to do that for them, they're going to have to sign a rate that's higher than spot today. James Knowlton Wicklund - Crédit Suisse AG, Research Division: So you would say that you have -- you're more of a price -- you're not as much a price taker as you've been in the past. Is that fair?

I would say we're still a price taker, but we're trying to make sure the optimality is on our side as opposed to theirs. James Knowlton Wicklund - Crédit Suisse AG, Research Division: Fair enough. The second question, if I could. RPC yesterday announced they were adding horsepower. You guys are announcing you're adding horsepower. I'm assuming this is in part because you can and other people can't. And that kind of assures you of expanded market share down the road. Is that fair?

Jim, I would say that the prevailing reason for making this decision is -- are twofold. One is that, the point that we made before, which is that we've seen this increase in drilling, and we believe that pressure pumping logically follows. And so we see that sort of coming about as the year progresses. And the second thing is that any number of our customers are speaking to us about increased needs for frac crews, and we don't want to be in a situation with our crews pretty much spoken for that we are unable to meet those demands. And so the view is that we needed to have this additional rig -- frac fleet at least in the pipeline, so that we would be able to meet some of that expected demand. James Knowlton Wicklund - Crédit Suisse AG, Research Division: Okay. And my last question, if I could. Two of the big 3 announced they were gaining market share in pressure pumping. The third said they were holding steady. So it was obvious that it's those other people who are losing share, but we can't figure out who those other people are. You are adding capacity, so it wouldn't seem like you're losing share. Who is losing share in this market?

That's a good question. This is a market that still has over 50 different players across the lower 48. We're up in the northeast and we're in Texas. It makes it a little bit more challenging for us to call U.S. market share number. But we're certainly confident in our position and ability to deliver. That's why we've ordered the other 40,000 horsepower.

Jim, we saw a huge number of entrants into this business financed by private equity. It's hard for us to know how those companies are all doing because most of them are private and don't report.

Next question is from the line of Pete Knerr from RBC.

It's Kurt Hallead here. Did most of the Q&A session, but not your prepared commentary. I want to follow on to Jim's line of questioning, which is there seems to be some consensus view that the excess capacity and frac market-wide is now down around 10% versus maybe the prior commentary, which would indicate around 15%. So that's probably idle capacity available to the marketplace. We have heard from you and a couple of other players that they will be adding capacity to the market. And you indicated that you're adding capacity to have it available should you get a call. So I guess you can imagine why I'm scratching my head, it's like, why would they need to call on Patterson or just anybody else when there is 10% available capacity still in the marketplace? That's just kind of where I get a thought on that. But the bigger question is, as an industry, and we're just getting back to the point where you guys could start to really lever pricing and now you're adding capacity on top of that? To me, that's -- that doesn't really bode well. So what's your take on that?

Well, the first point is that we are not waiting for the customers to call us. Customers have been in active discussions with us about their expectations of additional frac plates. And so quite frankly, we're uncertain, as the business increases, whether we're going to able to meet the demand for their needs. But at least having an additional fleet on order will at least assist us in that. And so you make it sound extremely speculative, I don't see it as speculative the way you've put it. That's the first point. Second, what we're saying, and I guess I haven't made this -- or we haven't made this clear enough is that with more than 150 rigs having gone back into the marketplace since last summer, we see a substantial increase in the number of wells being drilled and therefore, a substantial increase expected in the number of wells that will need to be frac-ed. Add to that increasing frac intensity and we think that the market will be reaching equilibrium. Yes, we think that there will be some better pricing. We've said that, but we also think that our position and the margins we've been able to achieve has been pretty impressive over the many years we've been in the business. We have not been one of those players who has operated at the smallest, leanest margins. We've been one of the least expensive operators trying to say that we price the most aggressively.

And I guess my take on it then is there probably isn't 10% spare capacity if you and others are adding and you're getting inquires from customers because I'm sure if they call around and they ask and if they were available, they'd be using it and they wouldn't be asking you to help them out. So maybe you were not even at 10% spare capacity?

Since we are not in every market in the U.S., it's hard for us to put a number on exactly how much spare capacity is out there. But certainly, if you focus on the Permian, that market is getting tighter. We expect that many of the frac fleets in the Permian all had some kind of work within the last month or so based on our estimates. And we expect activity to continue to improve in the Permian. So we need to have that 40,000 horsepower towards the end of the year. We were actively trying to push pricing in Q1 to see how much success we could get. We had a few small successes. And we will continue to actively try to push pricing. It's -- I don't know how that's going to look yet, but there's no question when you get back to the macro of the number of rigs are coming into the market in total across the U.S. and especially in the Permian. Horizontal drilling activity is increasing, the frac intensity is increasing, the number of stages per month continues to grow in the industry. And we're going to get to equilibrium in pressure pumping.

What's the price for horsepower that you're paying for this new -- for this crew?

We picked it up in general for less than $1,000 new.

Okay. And then lastly, can you give us an update on your thoughts on expanding internationally? And in context of that, I guess I'll ask it in a tongue-in-cheek way, why do you still have rigs in Canada?

We think Canada for us is still a long-term good market. The interesting thing is about the rigs that we run in Canada. We typically run the triple rigs. We're drilling horizontal wells with triple rigs in the plays like the Montney and the Duvernay today, which are the plays that we'll be exporting natural gas through the LNG systems off the West Coast. So we're very happy to be in those plays. We think long-term, we're going to have opportunities in Canada. So it's still a core part of our business.

But outside of Canada, what's your thought on and what's your update there, on your thoughts on where you might go?

No real Update. We have called out that we're pursuing international opportunities organically. It's not anything that's going to be meaningful in 2014, and it's just going to take time to put all that together.

The next question is from the line of Brad Handler from Jefferies.

My question was going to be and it still is, why are you only ordering 40,000 horsepower? But the reason I ask it from that vantage point is, you basically are adding one crew and maybe a little bit of spare, I guess. But given this very robust outlook that you are outlining, and I'm sure you feel like you have more than one customer opportunity that's lining up, why not put forward a little bit more spare capacity? I mean, 6%, one crew is just not a lot, right? So why aren't you, if you will allow me to ask you this way, by approaching it a bit more aggressively?

I think -- let me just start by saying we are very positive about the pressure pumping business. Back to the macro that we discussed, we see increase in utilization steadily throughout 2014. There is some lead time on the equipment. Could we order more than 40,000 horsepower? Yes. I think we're still cautious though. We still see some oversupply today. We see that that's going to work towards equilibrium. I think it's hard to know exactly how fast it's going to get to equilibrium. If we want to add more capacity later, I certainly think that we'll have that option with our Board of Directors. But right now, we've just got 40,000 horsepower in order. Mark?

Well, I guess, I will just add -- responding is, it's a measured approach. It's interesting to realize that on the same call within the same few minutes, one can take the view that we've ordered too much and one can take that view that says we've ordered too little. Obviously, management and the board spends a fair amount of time trying to make the right judgments about how to allocate capital. We think that over the years we've been pretty successful at doing that. We think this is a good judgment call about how much capital to allocate and recognize that we think that we could increase it if we think that later on we have under-allocated or in effect has been careful with it before. Historically, we have been able to achieve good margins in pressure pumping and expect to continue to do that.

Yes, that's a fair answer and it makes sense. If you chose to order more, could you still get it by year end, as your sense of the capacity in the marketplace?

Depending on the timing, it'd be close. Considering we've been buying new equipment off and on for over a year, we're pretty good customer for suppliers.

The next question is from the line of James Schumm from Cowen.

So you mentioned potentially 80 to 100 newbuilds this year. And high-spec rigs are seeing utilization rates north of 95%. So is this current level of building enough to knock those utilization rates down a bit by the year -- by the end of the year or what are your thoughts on that?

So as an industry, we see about 80 to 100 new high-spec rigs coming into the market throughout 2014. Our APEX utilization right now is at 97%. And so we don't see that, that number of rigs is going to decrease overall utilization at the end of '14 or even early '15. And that's why we've had to increase the amount of rigs that we're building in the program and added 6 more rigs.

Okay. And then, sorry if I missed this, but in pressure pumping, are you seeing any cost increases with respect to sand or other materials?

The winter in Q1 really took its toll in a lot of areas. Some of it had to do with sand cleaning at the mines, transportation of sand at certain basins. We've seen some increases. Not sure if that's really going to hold out through the rest of the year, as we get past the effects of the winter in Q1 that may start to level out. We'll just have to see how it goes.

We have no further questions on the telephone at this time.

Well, I'd like to thank everyone for joining us on this call and look forward to speaking with everyone as we report our results at the end of the second quarter. Thanks, everybody.

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