Patterson-UTI Energy, Inc. (PTEN) Q2 2014 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Second Quarter 2014 Patterson-UTI Energy Incorporated Earnings Conference Call. My name is Denise, and I'll be the operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to Mr. Mike Drickamer, Director, Investor Relations. Please proceed.

Thank you, Denise. Good morning, and on behalf of Patterson-UTI Energy, I'd like to welcome you to today's conference call to discuss the results of the 3 and 6 months ended June 30, 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 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, 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'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 second 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 June 30, 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'll provide some closing remarks before turning the call over for questions. Turning now to the second quarter. As set forth in our earnings press release issued this morning, we reported net income of $54.3 million, or $0.37 per share. Consolidated revenues for the second quarter of $757 million represented a quarterly record for the company, and pressure pumping revenues of $307 million were likewise a quarterly record for the segment. We are pleased with the quarter, as pressure pumping utilization and U.S. pricing both exceeded our expectations. We also benefited from investments made to transform our rig fleet and to expand our pressure pumping services. We are also benefiting from strong industry fundamentals. Demand for high-spec rigs remains strong. In addition to the growth of our rig fleet, we were able to achieve 99% utilization for our APEX rig fleet. We added rigs to our APEX newbuild program and at the same time, customer demand continued to accelerate. We are in the very positive situation of being almost sold out of our new APEX rigs over the next 4 quarters. The demand for high-spec rigs and the increase in horizontal drilling activity led to an increase in pressure pumping demand during the second quarter. A lag in pressure pumping demand relative to the rig count is normal, as wells have to be drilled before they can be completed. The increase in our customers' activity levels during the second quarter exceeded our expectations. In addition to ordering new horsepower, we completed the acquisition of a pressure pumping business during the second quarter. This acquisition provided us with a new base of operations in East Texas, further expanding our pressure pumping capabilities in Texas and Louisiana, 2 states that account collectively for almost half of the horizontal rig count in the country. With that, I'll turn the call over to Andy.

Thanks, Mark. Following our typical format, I'm going to start this morning with some commentary on our drilling business and then finish with some comments on pressure pumping. Our average rig count in the U.S. increased by 8 rigs in the second quarter to 201 rigs from 193 in the first quarter. Our growth in the U.S. rig count more than offset the spring breakup in Canada, where our average rig count decreased to 3 rigs in the second quarter from 10 rigs in the first quarter. Demand continues to increase with our average rig count in July expected to average 207 rigs in the U.S. and 9 rigs in Canada. The increase we have seen in our rig count has been geographically broad-based. During the second quarter, each of our regions reported sequential rig count growth. This growth in the rig count is unlike the recent past, where the demand was uneven and the weakness in one market served as a source of incremental rig supply for the stronger markets, such as the Permian. We believe this broad-based strength has helped contribute to the tightness in the market for high-spec rigs. With this improving market, average U.S. revenue per day increased $490 sequentially to $23,490 due to higher dayrates and an improving fleet mix of higher dayrate APEX rigs. The strength in average U.S. revenue per day offset the impact from the spring breakup in Canada, with the total average revenue per day increasing $240 to $23,630. The strength in the U.S. rates led to a better-than-expected increase in the average U.S. rig margin per day of $370 sequentially to $9,900 and an increase in total rig margin per day of $270 to $9,870. Of note, while our greatest dayrate increase has occurred for our higher-spec APEX and other electric rigs, average U.S. dayrates increased across all 3 of our rig classes during the second quarter. Looking forward, during the third quarter, we expect further growth in our U.S. rig count, as well as the ramp-up in our Canadian rig count. In the U.S., we expect our average rig count to increase an additional 8 rigs to 209 rigs, and in Canada, we expect an increase of 6 rigs sequentially to 9 rigs in the third quarter. In total, we expect a very healthy increase of 14 rigs to our average rig count for the third quarter. With the expected increase in activity and the continued tightness in the skilled labor market, we implemented a wage increase at the end of the second quarter, which we passed through to our customers. Accordingly, this wage increase will be reflected in our third quarter results as an increase in both our average rig revenue per day and average rig operating cost per day. Considering this wage increase, plus further improvement in both dayrates and fleet mix, we expect our average U.S. rig revenue per day during the third quarter to increase $350 and our average U.S. rig margin per day to increase $200. With the ramp-up in our higher-margin Canadian activity, we expect our total average rig revenue per day for the third quarter to increase $500 and our total average rig margin per day to increase $250. We completed 6 new APEX rigs during the second quarter, bringing our APEX fleet at June 30 to 133 rigs. Since our last earnings release, we have signed 19 contracts for new APEX rigs. In response to stronger customer demand, we expect to complete 25 new APEX rigs during the 4 quarters ending June 2015, of which 22 are currently contracted. Furthermore, we have customer contracts for 3 additional new APEX rigs to be completed in the second half of 2015. As of June 30, 2014, we had term contracts for drilling rigs, providing for approximately $1.5 billion of future dayrate drilling revenue. Based on contracts currently in place, we expect to have an average of 149 rigs operating under term contracts during the third quarter and an average of 138 rigs operating under term contracts during the last half of 2014. Turning now to pressure pumping. We generated record quarterly revenues of $307 million from pressure pumping during the second quarter. Of the $66 million sequential increase in pressure pumping revenues, most was related to better-than-expected equipment utilization across our existing fleet, and $9 million was attributable to the acquisition in mid-June. The fleet of 31,500-horsepower that we acquired in mid-June started a large job soon after the acquisition. Due to timing, we benefited from an unusually high level of utilization in sand volumes for this horsepower during this short period. Revenues from this equipment are expected to return to a more normal level going forward. With the growth in revenues, pressure pumping EBITDA increased by $24 million to $60 million, and our gross margin as a percentage of revenues increased to 21.1% from the weather-affected 16.8% in the first quarter. Looking forward, based on our customers' current schedules, we expect third quarter pressure pumping revenues to increase $30 million sequentially. Gross margin percentage is expected to remain relatively flat, despite the increase in revenues as pricing improvement is expected to be focused on offsetting higher costs related to materials and transportation. Additionally, we expect to incur personnel-related startup costs associated with the new frac spread to be activated in the fourth quarter. Our pressure pumping fleet at the end of the second quarter included more than 790,000-horsepower, of which, more than 709,000 is frac horsepower. We recently ordered an incremental 115,000 frac horsepower. Together with the previously announced 40,000-horsepower on order, we now have a total of 155,000-horsepower on order, enough equipment for 3 complete frac spreads plus spares. One of these spreads is contracted to be activated early in the fourth quarter in Texas, a second spread is expected to begin operations in the first quarter of 2015 in Texas, and a third is contracted and expected to be in operation in the second quarter in the Northeast. This horsepower was ordered to meet increasing activity levels from existing customers. Two of these spreads are already contracted, and we are highly confident in our ability to contract the third as several of our current customers have indicated that they will need additional horsepower in 2015. Moving on to pressure pumping technology. We believe we are a leader in bi-fuel frac technology that uses natural gas as a fuel source for the equipment. During the second quarter, we converted another complete spread to bi-fuel and we have now converted a total of 111,000-horsepower, or approximately 1/3 of our frac fleet in the Northeast. In the Marcellus, we have completed approximately 1,000 stages using natural gas as a primary fuel source. Additionally, we recently converted 11,000-horsepower in Texas to bi-fuel and are testing the use of the technology in that region. In another area of technology, our recent award of a frac fleet in the Northeast for delivery in 2015 was based on our ability to provide quality services with specific technology related to emissions and air quality while working in a sensitive area. We continue to focus on differentiating ourselves in this business through excellent well site execution, the introduction of new technologies and strategic locations to support our operations. Before I turn the call back to Mark for his concluding remarks, let me provide an update on a couple other corporate financial matters. We expect to spend approximately $1.1 billion of CapEx in 2014. We expect our effective tax rate to be approximately 32.5% in 2014. SG&A during the third quarter is expected to be $19.5 million. Depreciation expense during the third quarter is expected to be $158 million. And with that, I will now turn the call back to Mark for his concluding remarks.

Thanks, Andy. Industry fundamentals are strong and are continuing to improve. We are optimistic about both the magnitude of the improvement and the duration of the improvement. Our country is moving towards supplying our domestic energy needs with domestic source of energy. Nobody would've thought this concept possible 10 years ago, but advances in drilling and completion technologies have made this a reality. These advances in drilling and completion technologies are allowing us to drill deeper wells with longer horizontals and to produce oil and gas from rock that was previously thought not to be conducive to production. Drilling and completion technologies continue to improve, allowing us to drill and complete more complex wells and to do so more efficiently for our customers. As technology continues to improve, one constant is that drilling rigs and pressure pumping horsepower are still the platform by which these technologies are deployed. With our focus on these 2 product lines as our core businesses, we continue to believe that we are well positioned within the oilfield service industry for sustained growth. Now, as technologies have advanced, the rigs and pressure pumping equipment have also needed to evolve. Investments we have made in our company have both transformed our rig fleet and expanded our pressure pumping fleet, thereby strongly positioning us in both of these businesses. In contract drilling, we have 133 high-spec APEX rigs in our fleet. Demand has been strong for these rigs. As such, we have seen dayrate increases across all classes of rigs in our fleet, and we have approximately 70% of our rigs operating under term contract. These rig term contracts enhance our visibility, respecting our future earnings and bolster our confidence in the expected duration of the domestic energy resurgence. Moreover, as we think about these trends, perhaps most striking is that certain customers have signed long-term contracts for rigs that are slated for delivery in the latter part of 2015, thus contracts extending into 2018, which further underscores our belief that we are in the early innings of this trend. In pressure pumping, investments to enhance our fleet and efforts to differentiate our services include a market-leading position in the Marcellus for bi-fuel pressure pumping and new lab facilities in the Permian that among other things, help our customers overcome issues with reusing produced water. With that, I'd like to both commend and thank the hardworking men and women who make up this company, as well as -- as it is their focus on our customers that helps to differentiate us. I am pleased to announce today the company declared a quarterly cash dividend on its common stock of $0.10 per share to be paid on September 24, 2014 to holders of record as of September 10, 2014. Operator, we would now like to open the call to questions.

[Operator Instructions] Our first question comes from Jim Rollyson with Raymond James. James M. Rollyson - Raymond James & Associates, Inc., Research Division: Andy or -- when we look at pressure pumping, you mentioned pricing, it sounds like at this point, is basically going towards offsetting increased cost for materials and handling, logistics, et cetera. At what point -- as you size up the market right now, what point do you think you'll get to where pricing actually leads to margin benefits?

That's a good question. I think we're certainly upbeat about where we are in the market right now. The fact that we can get pricing improvements is a big shift from where we were. But we are seeing the higher cost in materials and transportation. And right now, these price increases are just offsetting those higher costs. Now, if you look at the markets in Texas, we're very busy and we're very close to what we call equilibrium in those markets. So you could envision sometime in the future, that we're going to transition to where these price increases will also add to margin. James M. Rollyson - Raymond James & Associates, Inc., Research Division: That's helpful. And when you think about the growth in capacity you have coming between the fourth quarter and the second quarter of next year, how are you set for materials, like proppant's been a big topic of shortages this year. I'm kind of curious how well you guys are prepared for being able to fulfill the new capacity.

We're comfortable with our position in the area of products, not just proppant but various chemicals that we require for this business. With our size and our procurement and supply chain processes we have, negotiations that we've had with various suppliers, we think we're in good shape for this. James M. Rollyson - Raymond James & Associates, Inc., Research Division: Great. One question, just switching gears to the rig side of the business. Sounds like demand is obviously pretty exceptional. Mark mentioned having contracts that go into 2018 at this point. When you look at rates for rigs today and the leading edge, maybe just a little compare/contrast of where we are today across the different spectrum of rigs relative to where they were at the top of the last cycle.

I think we're not quite where we were at the top of the last cycle, which means we still got some room for improvement. We've signed 19 contracts in the last quarter on newbuilds, very excited about where we are in that space. We're seeing pricing moving up. We're seeing a shift to more of 3-year contracts as opposed to just 2- to 3-year. So terms and pricing, we're seeing that improve right now in the newbuilds.

Our next question comes from Byron Pope with Tudor, Pickering Holt. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: I have a question on the land rig side of the business. And I was struck by your comment that the dayrate momentum is behind all rig types. And so just curious as to -- so clearly, the AC end of the market is effectively at full utilization. I'm just curious as to what you're seeing for your SCR rigs and mechanical rigs as related to seeing dayrate momentum even for those rig types?

We're just seeing strong demand for drilling rigs in general, and we're seeing it across the board, we're seeing it in all regions across U.S. and Canada right now. So it's just a good market to be in with land rigs. It's especially tight on the high-spec, and when we get to this level of tightness, like we said, we're at 99% utilization on APEX. And because of that, that's also improving the demand for SCRs and mechanicals. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And given that you've now got 70% of your rigs under term contracts, is it fair to assume that some of your rigs that may have previously been working in the stop [ph] market, as you've had E&P operators come to you to even term out some of those existing rigs? Is that a fair assumption?

That's a fair statement. Operators are worried about their ability to get drilling rigs, and they're certainly willing to tie up rigs on term contracts. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And then last question for me is on the pressure pumping side. I'm just thinking about the delivery pace of the frac horsepower that you have on order, that first spread, early Q4. It seems a little earlier than what it seems like the market talk has been in terms of where the lead times are. And so, just curious as to what you're already seeing in terms of the key bottlenecks in terms of procuring additional spreads at this point. Is it more the spreads or is it associated equipment that comprises the spreads?

So we had previously announced that order for the 40,000-horsepower. We think we were early enough in the chain of supply to be able to get that. So we do expect to have that working early Q4. And we think we're a big enough customer for some of these suppliers. We don't see any real issues with lead times right now.

Our next question comes from Dave Wilson with Howard Weil.

Mark, I kind of wanted to revisit your comments about being in the early innings in relation to kind of longer-term kind of a run rate for newbuilds. I know you guys have got 25 slated for the next 4 quarters and then 3 after that. But looking at 2015, is it safe to assume that we're just kind of the back half of '15, we're adding about 6 rigs a quarter, or a little more than that?

We haven't set forth our building plan for the back half of next year. Frankly, we've come to -- want to speak to the next 4 quarters because we think that's the most useful way to address the market and to address what we're seeing and just consistent with lead times. But what we're doing is really taking a look at demand and our capacity to build and trying to match them in the best possible way for the maximization for our shareholders, as well as our customers.

I'll add to that. We're building 20 rigs in 2014. We're now saying that we're going to build 25 rigs over the next 4 quarters. So you are seeing us ramp this up. We have the ability to ramp-up more but we're building into the demand. We're looking at what our customer needs are, we're having ongoing discussions, and we're very pleased. Like I said a minute ago, where we are today in this space with our rigs and the pricing on our newbuilds moving up and it's shifting to more toward 3-year on terms.

All right. And then this is a follow-up on the strength and kind of across the board with the SCR and mechanical. Did you activate any more non-APEX electric rigs in the second quarter?

We did. We brought out one SCR, non-APEX electric.

Okay. And has that strength got any mechanical that you've reactivated as well or just the one with the...

One more mechanical.

Our next question comes from Waqar Syed with Goldman Sachs.

Andy, as for your announcement of 150,000, 55,000 hydraulic horsepower that you've ordered, you mentioned that there's only additional 3 crews. So as you look at average hydraulic horsepower per crew, how does that compare for these new equipment versus your existing? Is it, on average, the same or is it the new equipment, you're signing a lot more per crew?

So, that's a good question. What we're doing is we're ordering horsepower for the 3 extra crews plus spares. When you get to our size and the amount of 24-hour operation that we're doing, we have to have some extra pumps to be able to rotate through the maintenance cycle. And speaking of 24-hour operations, for the last few quarters, we were kind of holding steady at 75% of the revenue generated from 24-hour operations. We've now moved that up in the last quarter to 83% of the revenue generated from 24-hour operations. So that's a positive and that's where some of our increased utilization is coming from. And therefore, we do need some extra pumps in the system to be able to rotate through the maintenance process. As well or early in the year, we did some transitions from some smaller frac fleets just doing verticals into frac fleets doing horizontals, and we had to add some horsepower capacity to those fleets. So that's where it's all moving to.

So as you transition from 12 hours, 24 hours, what percentage of fleet is then -- that rotational that's going through the maintenance program at any point of time? Where does it stand today and maybe where it was when you were doing less 24-hour operations?

It's hard to break it down into a percentage of the fleet. You're talking about just 1 or 2 pumps at any given time.

So 5,000 -- 1 or 2 pumps, when you say a 5,000 hydraulic horsepower, is that how should we be thinking?

Potentially or maybe a little bit more.

Okay. Sounds good. Secondly, as you look into next year, obviously, you're getting sweet [ph] strong demand for your AC rigs, APEX rigs, how -- what's your view on the demand for SCR mechanical rigs? Do you see these rigs next year as well incremental? Or you start to see some softening or some cannibalization of the existing fleet?

Right now, with the visibility that we have and the newbuilds over the next 4 quarters, we see these newbuilds as incremental. We're still seeing strong demand in all regions and we don't see that any of these newbuilds are going out there to replace any of the existing non-APEX electrics or mechanical rigs.

Waqar, it's kind of interesting. It's the old Mark Twain comment about reports of my demise are greatly exaggerated. We see those reports as well about the mechanical rigs, and I think one of the reasons we wanted to highlight that the pricing was across the board in all 3 categories was to make the point clearly that in effect, it's across the board and it's not just the high-spec rigs, although obviously, those are doing the best.

Okay. And then just one final question on the dual fuel pressure pumping equipment. It is obviously adding value to your customer, maybe bringing down their operating -- their cost as they start to use some natural gas. Is that also having an impact on your own operating cost as well, bringing them down, too?

In pressure pumping, we buy the fuel. When we do a bi-fuel natural gas operation, we rely on the operator at that point to bring in the natural gas. We structure the contracts accordingly. And in some cases where we have the ability to improve the margin on those types of jobs, I think also that you need to take into account that our experience with this technology allows us just to do more work.

Our next question comes from Matt Marietta with Stephens.

Matt Marietta here. My first question on the geographic mix of newbuild APEX rigs. Where are these rigs generally going with the new contracts that were announced? And can you maybe talk a little bit about the customer mix? Are these legacy customers or are you seeing new customers come to the order for the APEX rigs?

So first, regarding the regions, we're putting new APEX rigs into just about every region in North America right now. So we're excited that this is still broad-based, and it's one of the reasons it's just driving an overall tight market. With customers, we don't get into specifics, but we are certainly proud of the fact that we have a very broad customer base. We're talking about multiple customers in this last round of 19 newbuild contracts, and a few of the customers signed up multiple rigs.

And along the same lines, are you seeing your customer base look for specifically, the walking systems on the APEX rigs versus the skidding systems that are also out there in the market? And can you maybe speak to any preference on the actual mobilization system of the rigs?

Our focus is on the walking systems. We think it allows the most flexibility around multi-well pads, ease-of-movement, just lots of options for the operator. And certainly, the rigs that we're building and planning to build going forward all have the walking systems.

Our next question comes from Pete Knerr with RBC.

It's Kurt here. So I wanted to follow up on Waqar's question on the land drilling and the high-spec versus the mechanical, and I was hoping you guys could help educate me a little bit more as to why in the world anybody needs a mechanical rig.

Well, as we discussed, there's strong demand across all regions right now for drilling rigs and we're at 99% utilization on APEX. So if we've got customers that just can't get into an APEX rig, they're certainly willing to pick up another rig. But like I said before, that doesn't mean that this becomes a replacement. Everything that we're putting out going forward for the next 4 quarters, it's incremental as far as we can see right now.

And for that mechanical rig dynamic though, how many are being retrofitted for -- how many are being retrofitted for horizontal? How many rigs within your fleet can ultimately be retrofitted for horizontal work?

Any of the rigs in our fleet can drill a horizontal well. It depends on the additional equipment that's on there. We've stated in the past that many of the mechanical rigs that we have today have upgrades of AC top drives, they all have iron roughnecks on them. So they've got a lot of advanced equipment. You're not going to see people throwing chains on our mechanical rigs. So in general, our mechanical fleet has a lot of upgrades already.

And our mechanical fleet drills a lot of horizontal wells when we're drilling a lot of gas wells.

Now, the other thing I was curious about was getting a lot of inquiries from investors looking for the crash landing on the U.S. land rig market in terms of overbuilding just as we're starting to take off, it seems a little bit premature to me. But I wanted to -- I guess, I'm setting you up with a softball question. I wanted to get a sense from you as to are you guys starting to get nervous about all the new building that's taking place? What you think the crossover point could be on supply demand, and maybe lever that into another question relating to the economics you think we can hit. Do you think we can exceed prior peak pricing levels for high-level, high-spec rigs?

Well, there's several parts to that question. So let me start first with where we are in the overall build. No, from our standpoint, we don't have a concern. We're still signing up newbuild contracts, we're almost sold out over the next 4 quarters, so we feel like we're in good shape when it comes to the newbuilds that we're building right now. If you look at where the industry is in general in the cycle, there's probably still upside. There's just a very broad-based demand across all regions right now, so it leads us to believe that we still have room to go as far as the cycle. And if you look at the bigger picture in terms of operator demand long-term to drill horizontal wells, operators want to build to drill horizontal wells and improve their efficiencies. And to do that, you need to be in a high spec rig and if you're on a multi-well pad, you need to have a walking system to be able to do that. And if you look at the number of rigs that are out there drilling horizontal wells and the percentage of which is high-spec. It's still only roughly 50%, so there's still a big fairway left in front of us in terms of retooling the industry over to high-spec rigs in the U.S.

What about the pricing dynamic? I've heard that the newbuild cost continues to creep up. So, with $27,000, $28,000 a day, the economics to build a new rig are less than what they were in the prior cycles, so you can actually build a case for getting a dayrate well in excess of $30,000 to match a prior cycle economics. What's your take on that?

In our particular case, we announced it last year, we were able to reduce the cost of our newbuild by about 10% and we're not seeing any cost escalation on that right now. So we're pleased with the economics around the newbuild.

You still haven't answered the question on the pricing, Andy. You're doing pretty good.

I thought I answered that in terms of the cycle. I think we're still in early -- I think we still have a ways to go in the cycle, so I don't think we're at the peak pricing level of the previous cycle, and I think that there's still room for pricing to go up.

Our next question comes from Mike Breard with Hodges Capital.

I was going to ask about rig cost but it's already been answered.

Our next question comes from John Daniel with Simmons & Company. John M. Daniel - Simmons & Company International, Research Division: Andy, when you propose the initial terms on a newbuild rig to a customer, are you getting all of those terms or do they still have the ability to negotiate you down on certain items?

I would say there's been a shift in the market over the last year. And just to give you an example, as I stated earlier, it was for the last couple of years that our term contracts were in that 2 to 3 range. Now they're almost primarily 3-year contracts, and we've seen pricing go up. I mean, that's the best way I can describe it. John M. Daniel - Simmons & Company International, Research Division: Okay. Fair enough. I want to follow up on Waqar's questions about sort the frac business. About how many of your pumps will you rebuild in this year and how does that compare to last year?

There's no change and I don't anticipate any major rebuilds on any pumps. We're constantly doing preventive maintenance on pumps. As you well know, we repair the pump assembly at a certain number of hours, the transmission at a certain number of hours and the engine gets serviced at a certain number of hours. But we're certainly not expecting any major rebuilds on any of the equipment. John M. Daniel - Simmons & Company International, Research Division: Let me ask it another way. Can you share with us what the maintenance CapEx is for the frac business this year versus last year?

I don't have those numbers in front of me. I don't expect, as a percent, that it's going up any different from our activity level, so we're not expecting any change. There's a lot of discussion around age of the equipment and what does that mean, but to be honest, we're just not seeing anything that gives us any indication that we're approaching the end of the life on our equipment. John M. Daniel - Simmons & Company International, Research Division: Okay. But you're saying that maintenance, as a percentage, is the same with maintenance dollars, the spending is going up?

In line with activity. John M. Daniel - Simmons & Company International, Research Division: Okay. And then the last one. I don't -- if you said this earlier, I apologize. But I haven't heard anyone ask about the purchase price on the acquisition. Is that something you can comment on now or will it be disclosed in the 10-Q?

We don't consider that material, so it's not going to be disclosed at this time.

[Operator Instructions] Our next question comes from Brad Handler with Jefferies.

I guess my questions may feel like you've answered them couple of times already, so I apologize. But in the last 6 months or maybe the last 3 months for the contracts you've signed for newbuild rig contracts, is it at higher pricing than the prior 6 months?

Yes.

Okay. That's all right. That's fine. I wasn't even sure I'd heard that as clearly, so very good. And your newbuild rig costs have remained steady, you've said?

Correct.

Okay. Out of curiosity, have the newbuild rig costs remained steady because the equipment, the pieces are also being purchased at the same price? Or are those -- is there some inflation there but you're able to offset those through efficient assembly?

I think in our particular case, we're a big enough customer for a lot of these suppliers with the number of rigs we've been building over the years, that we're able to just have consistent negotiations and consistent supply chain on this and we just haven't seen any escalation.

Okay. May I ask the same question related to fracturing horsepower? Do you see any signs of inflation on frac horsepower equipment? Maybe not in what you just ordered, but if you were to order more, do you think the industry has moved into that position at all?

I don't think the industry's moved into a position where we would have to pay more for the horsepower right now.

Our next question comes from Chuck Minervino with Susquehanna.

I just wanted to touch on the pressure pumping margins and gross margins and operating margins, and just kind of looking back to 2011 and 2012 levels, the gross margins kind of were in that high 20s, low 30s kind of level, and we're still kind of very low 20s right now and just kind of got into that level. I just wanted to get a sense from you, what needs to happen here going forward to kind of revisit those prior levels? Is that possible? It seems like you're running about as efficient as you can be right now, so I was just curious if that is something that is an achievable number kind of in this cycle.

Certainly, 2011 was a peak of the cycle. We came out of 2011 and 2012 where we saw both downturn in natural gas and the price of crude oil and a slowdown in the requirements, and we had to give price concessions. The good news about our business, and you see that, that we run a very healthy business, we never had to stack any of our equipment in 2012 and 2013, and we slowly grew our business as well at the same time. I think, in this particular cycle, we're still in early phase. We're very busy in Texas right now with our operations, and that market is very close to equilibrium in that supply-demand balance. In the Northeast, we probably still got some oversupply in the North East and as far as the industry goes, all of our equipment is working and we're very pleased with the progress that we made up there. And don't forget, in general, we've made more dollars here recently than we did in 2011, so we're actually producing more earnings from this business. But in terms of margin, I think there's still room for improvement. We are getting some price increases, as I've talked about earlier. But right now, these are just covering the additional costs. But as the industry overall gets closer to equilibrium and demand increases, then there's that potential to increase pricing past what we're just getting for cost recovery. Don't forget the macro. The macro is that we're putting out, as an industry on the drilling contracting side, more new high-spec rigs that are going to drill more horizontal wells and that's just going to drive the number of stages per month required for hydraulic fracturing on the pressure pumping side of the business.

Yes. It looks like you haven't even exceeded the number of frac jobs you did back in, I call it, 2Q 2012. So it makes you wonder if there is more to go on these frac jobs. I mean, I know frac jobs isn't really just kind of a strange metric to use here for modeling purposes, but can you comment on if there's more room on that side of the business that more stages to grow, et cetera?

So I will say that while we don't call out the number of stages that we do, in general, the number of stages per job has increased. So while job count may look relatively flat back to 2011, the number of stages per job has gone up.

We have no further questions. I would now return the call back over to management for closing remarks. Please proceed.

I'd like to thank everybody for joining us on this call, and look forward to speaking with everyone when we report our third quarter 2014 results in October. Thanks, everybody.

This concludes today's conference. You may now disconnect. Have a great day.