James Michael Drickamer - Director of Investor Relations Mark S. Siegel - Chairman and Member of Executive Committee William Andrew Hendricks - Chief Executive Officer and President John E. Vollmer - Chief Financial Officer, Principal Accounting Officer, Senior Vice President of Corporate Development and Treasurer

Robin Ernest Shoemaker - KeyBanc Capital Markets Inc., Research Division James M. Rollyson - Raymond James & Associates, Inc., Research Division David Wilson - Howard Weil Incorporated, Research Division James C. West - ISI Group Inc., Research Division Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Jason A. Wangler - Wunderlich Securities Inc., Research Division John M. Daniel - Simmons & Company International, Research Division James Knowlton Wicklund - Crédit Suisse AG, Research Division Brad Handler - Jefferies LLC, Research Division Scott Gruber - Citigroup Inc, Research Division Angeline M. Sedita - UBS Investment Bank, Research Division Michael Breard - Hodges Capital Management Inc.

Good day, ladies and gentlemen, and welcome to the Third Quarter 2014 Patterson-UTI Energy Inc. 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 turn the conference over to Mr. Mike Drickamer, Director, Investor Relations. Please proceed, sir.

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 9 months ended September 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 third 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 September 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 third quarter. As set forth in our earnings press release issued this morning, we reported net income of $16 million, or $0.11 per share, which includes the effect of a noncash charge. Consolidated revenues for the third quarter of $846 million, represented a quarterly record for the company, and pressure pumping revenues of $349 million were also a quarterly record for the segment. Included in the financial results for the third quarter is a pretax noncash charge of $77.9 million, or $0.36 per share after-tax, related to the company's mechanically powered rig fleet. This noncash charge reflects the retirement of 55 mechanical rigs and the write-off of excess spare components for the now reduced size of the company's mechanical rig feet. The decision to retire almost all of our idle mechanical rigs reflects the shift in customer demand away from mechanical rigs to modern high-spec rigs, such as our APEX rigs. As a result of the retirement, we have 44 mechanical rigs remaining in our fleet with a net book value of $113 million. This group of rigs has maintained a high level of utilization and generated more than $85 million of EBITDA over the past 4 quarters. The cash flow from the active mechanical rigs is helping to…

Thanks, Mark. And following our typical format, I'm going to start this morning with commentary on our business and some of the elements of the fundamental transformation of our company. Our average rig count in the U.S. increased by 8 rigs in the third quarter to 209 rigs from 201 in the second quarter. In Canada, our average rig count increased to 10 rigs in the third quarter from 3 rigs in the second quarter. Overall, we continued to experience high levels of rig demand, as our rig count in October is expected to average 212 rigs in the U.S. and 10 rigs in Canada. Strong demand for high-spec rigs is positively impacting rig pricing. Average rig revenue per day and average rig margin per day both increased sequentially across all of our rig classes. Average rig revenue per day in the third quarter increased $380 sequentially to $24,010, and average rig margin per day increased $290 sequentially to $10,160. Looking forward, during the fourth quarter, we expect to average 214 active rigs in the U.S. and 10 in Canada. Average rig margin per day is expected to increase $300 driven by an increase in average rig revenue per day. As of September 30, 2014, we had term contracts for drilling rigs providing for approximately $1.7 billion of future dayrate drilling revenue. Based on contracts currently in place, we expect to have an average of 157 rigs operating under term contracts during the fourth quarter, and an average of 93 rigs operating under term contracts during 2015. We completed 6 new APEX rigs during the third quarter, bringing our APEX fleet at September 30 to 139 rigs. Since our last earnings release, we have signed 7 contracts for new APEX rigs. Further to this and in response to strong demand…

Thanks, Andy. North American land drilling and pressure pumping are excellent businesses, and we are well positioned in both of these segments. In contract drilling across the industry, high-spec rigs continue to be in short supply. Within our fleet, utilization remains strong for APEX rigs and pricing has improved. Demand for rigs under term contract remains strong. We are pleased with the large number of rigs we have under term contract and expect this trend will continue. In pressure pumping, demand is increasing due to greater horizontal drilling activity and increasing frac intensity per well. We are increasing our scale through both accretive acquisitions and incremental new equipment orders to meet the rising demand from customers. We believe that supply logistics associated with the increasing frac intensity has become a differentiator among competitors, and we will benefit through our position as a high-quality execution-focused pumping company. In addition to our strong operational positioning, we believe we are well positioned financially. Our balance sheet provides us with options to continue strong return generating projects, such as new APEX rigs or adding pressure pumping capacity, as well as returning capital to shareholders. Our outlook remains positive but we are well aware of recent softness in oil prices. It's too soon to tell how this softness will affect our customers' drilling and completion plans. But thus far, we are not seeing a change in activity levels. And we expect our rig count and pumping activity to increase quarter-over-quarter. With that, I would like to both commend and thank the hard-working men and women who make up this company. I'm 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 December 24, 2014, to holders of record as of December 10, 2014. Operator, we would now like to open the call for questions.

[Operator Instructions] Our first question comes from Robin Shoemaker with KeyBanc Capital Markets.

Andy, I was wondering if you could elaborate a little bit on your sand contracting strategy, given the fact that you had some additional costs and demurrage and so forth. And also, you're significantly expanding your horsepower in service, which would require you to get more sand contracts lined up. So just wondered if you could elaborate on that a bit.

So when it comes to sand and logistics, we're pleased with where we are today. In the third quarter, we didn't miss any work because of lack of sand. We're buying sand from mines in various places across the U.S. As you've seen in our filings, we have an investment with a mine as well. And so we're confident with the contracts that we have in place, and we didn't see any shortage in sand in the third quarter. And we're certainly confident that we can support the horsepower that we've acquired at the same time going forward and the new horsepower that we're going to receive in 2015. We did have some increased demurrage charges in the third quarter, and that was really due to the weather and what held us up in West Texas. We had jobs that we couldn't pump because of the weather, but we had sand ready for the jobs, and we were paying the demurrage. It's a little bit tongue in cheek, but it's an interesting fact that if our supply chain and logistics people weren't as good as they were and we didn't have sand, we wouldn't have incurred the demurrage costs and our margin would have been a little bit higher.

Okay. And if we turn to the rig contracting, I just wanted to ask you about your rollovers here recently as term contracts expire. Are you -- as rigs come off contract, are you continuing to sign some contract extensions? Are more rigs going on a well-to-well basis? And on -- I think you mentioned in the fourth quarter is 70% of your rigs in service will be on term. And obviously, the backlog doesn't keep it at that rate for '15, but would you expect on your rollover strategy that you would be able to come close to 70% through 2015?

We are not seeing any change in the trends when it comes to contracting other than the continued push on pricing. We see that as contracts role, especially on the APEX, the high-spec rigs that we have in our fleet, pricing is continuing to push up. We do see customers wanting to extend and hold onto rigs. Our utilization in APEX is almost 99% right now. We just don't have APEX available really today if a customer needs one. And that just shows you the strength in that market.

Our next question comes from Jim Rollyson with Raymond James. James M. Rollyson - Raymond James & Associates, Inc., Research Division: Andy, you sound pretty confident in the -- when you went through your prepared remarks about getting rigs out. And I think you've got, what, 8 rigs that aren't spoken for officially. But it sounds like conversations are going well to get those put to bed. Can you just maybe talk about how those conversations are going in the last month or so, given oil price declines? Have you noticed any slowdown in interest to contract new-build rigs? Or is that still keeping pace to where you guys will be delivering new builds all through the next year, do you think?

We are constantly in discussions with customers. And even over the last month, we haven't seen any change in flow of customers who've either wanted to come to our new construction yard or go out to the field to visit rigs and look at rigs. So we're just not seeing any indications right now of any change. James M. Rollyson - Raymond James & Associates, Inc., Research Division: Okay. And these are still predominantly in the 3-plus-year time horizon for the new contracts?

That's correct. If you look at the rigs we've contracted out to the middle of 2015. This -- the average is very close to 3 years. Any rig that we contracted for less than 3 years, the customers were willing to pay a premium to do that. So this is still a market where we're still getting good terms, and we still think we'll continue to push pricing on APEX rigs. James M. Rollyson - Raymond James & Associates, Inc., Research Division: That's great to hear. On the frac side, you guys have closed 2 acquisitions now, both in Texas. When you think about this going forward, are you more likely to continue to do deals like that or order new equipment or possibly some of both?

Right now, we've done that 2 acquisitions. We did the one in June, and we just closed the other one just here a couple of weeks ago. And that's a total of 180,000 horsepower in addition. We also just activated a brand new fleet here, right at the beginning of October. And then, we have 2 more fleets that we will activate next year. One in the first quarter, and one in the second quarter. So I think, in some ways our plate's pretty full, just making sure that everything goes well. Like I said earlier, we're certainly confident in our position with the sand contracts that we have and logistics to get the sand necessary for all the spreads that we have going forward. There will be a slight ramp up in utilization with the new acquisitions, as we work through that equipment. But overall, I would say that we are just going to work through what we have right now, and it's looking good for us with this increased level of horsepower going into 2015.

Our next question comes from Dave Wilson with Howard Weil.

Andy, just kind of following up on the 44 mechanical rigs you still have working, which are generating great returns, is there anything you can say about them collectively that would give us some comfort that they're going to continue to generate these types of returns going forward? Are they centralized in a central area or doing some type of drilling that minimizes the near-term risk that they could ultimately be replaced by a higher-spec rig?

That's a good question. We have been getting that for at least the last month as we've been traveling to some of the conferences. But we just don't have any visibility, especially through the first half of 2015, with the new builds that we are coming out with that any of the existing fleet is going to be replaced. If you look at our mechanicals that are working today, many of these rigs have top drives, AC top drives. They all have the upgrades like iron roughnecks, hydraulic systems on them. And so there is a lot of upgrades on the rigs that we have in this particular fleet that are out there. Many of them are drilling horizontal wells. They are really working under different types of projects than what you typically contract a high-spec APEX rig for. These might be smaller projects, maybe shorter term, something like that. But we just don't have any visibility right now that these are any kind of situation of being replaced.

Our next question comes from James West with ISI.

Andy, as you think about your new-build cadence, I'm pleased to see you moving that up to 8 a quarter. What is your constraint on moving that higher from here? Is it -- I'm assuming it's not capital. Is it the ability to get rigs out of the yard, get equipment, or is it more just rigging up these rigs with people?

It's really not about our manufacturing processes or our supply chain or our ability to get the parts and equipment that we need to put the rigs together and go through the qualifications. It's really about the market. We are very cautious about the market. We are increasing what we're planning to do because the market supports that. But we like the market where it is. We're going to continue to push APEX pricing. We're getting good paybacks on these rigs, and we're just in a good position right now.

Are the paybacks still in that... [Technical Difficulty]

Did we lose you?

I'm here. Are the paybacks still in that 4-year type range?

Over the last couple of years, the paybacks were in the 4 to 5 range. But if you look at what we're contracting into 2015, it's much closer to that 4-year range.

Our next question comes from Byron Pope with Tudor, Pickering. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Andy, I tend to think of you guys as having grown your frac business in the Northeast region and in the Southwest region to meet incremental demand from your existing customers. And so as we think about the 2 new frac spreads that will be going to work early next year, one in Texas and one in the Northeast, is that still the case, I'm assuming?

That's still the case. Yes. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And fair to think that those -- you mentioned that 90% of your Q3 frac revenues are from 24-hour operations. Fair to think that those 2 incremental spreads will be on similar type work?

Sure. That will likely to continue at those levels. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And then as you think about the pressure pumping business when you are already 90% on 24-hour operations, could you speak to maybe 1 or 2 sorts of examples as to how you could further eliminate white space in the frac calendar?

Yes, that's a great question. So we're really pleased at how we've been able to advance the amount of 24-hour operation work that we're doing, because it just improves the overall return on that business. But there is still some white space to fill out in the calendar. When you go out to a pad, and you work for 6, 7 days on a pad, 24 hours a day, then sometimes you have some gaps in these pads. With the extra horsepower, the extra fleets that we have, especially across Texas now, we have the ability to move things around and better fill out our calendar. And the extra horsepower just gives us more flexibility in this system when it comes to managing our calendar, especially across Texas. So we certainly see that -- as we've seen going through 2014, we've seen this increasing utilization, we've seen white space come out of the calendar. We think we'll continue to see that as we move into 2015 as well.

Our next question comes from Jason Wangler with Wunderlich Securities.

Obviously, you're talking about the utilization on the frac side, sounds like things are, obviously, going pretty well even as you integrate stuff. Could you just maybe comment on just what you're seeing in terms of price? You guys are, obviously, in 2 pretty good regions, but how you're seeing the pricing kind of move the last few months?

Yes, we've been able to get some price increases in Q3, with some of the extra costs we incurred. They really turned out to be closer to cost recovery. But we think, we're getting some net pricing increase as well. And we think that net pricing increase will continue into 2015. When we look at the margins going into the fourth quarter, we are only projecting around 21%. There is a mixture of seasonality in that. There's the costs with ramping up utilization on the latest acquisition and also crewing up the next frac spread going into Q1 2015. But overall, we see pricing going up in pressure pumping.

That's helpful. And just maybe on the buyback side, just kind of where your heads are at, obviously with what's been going on in the market. Obviously, you guys have been investing quite a bit in the business, but have you looked at maybe utilizing that again? Did it look like there was anything in the third quarter? But just maybe something on that?

Sure. I'm happy to respond to that question. We are constantly trying to evaluate whether it's an appropriate time to use capital to buy back shares. Frankly, we always consider it, and especially consider it when the stock price drops. As you know, from our most recent buybacks, we've been historically finding the stock more attractive at a little lower price than it currently is at. But certainly we'll consider it and happy to tell the shareholders that, that's always on our plate.

Our next question comes from John Daniel with Simmons & Company. John M. Daniel - Simmons & Company International, Research Division: Just want to start with a housekeeping item for John. What will you use for an average depreciable life for the recently acquired frac assets?

John, as I think you know, when we do an acquisition we'll hire somebody to do appraisal work on that. In that process, they're looking at the value of the equipment based on usage, et cetera, and it will also provide information about the remaining life. When we receive that, we will finalize the recording of those transactions and the depreciable lives. That will occur in the fourth quarter. John M. Daniel - Simmons & Company International, Research Division: Okay. So not ready to give a number yet for the years?

No, not -- the work's not completed. John M. Daniel - Simmons & Company International, Research Division: Okay. All right. That's fine. Just wanted to dig into the contract coverage for a second. In 2015 you've got the 93 rigs under contract. Presumably that includes the 22 of the 30 rigs being built. Is that right?

That's correct. John M. Daniel - Simmons & Company International, Research Division: Okay. Are any of the mechanical rigs under contract or is that all spot?

No, we have mechanical rigs under term contract as well. When you have the level of upgrades that we have on some of these rigs, they are still very popular rigs in some places. John M. Daniel - Simmons & Company International, Research Division: Okay. And so turning to the APEX rigs, when those contracts expire and the rigs are getting renewed, I know you don't like to give the specific numbers, but what's a typical or normal delta, if any, percentage wise, what [ph] have you, between the APEX rigs that have recently been built where the contracts have expired versus what the leading edge new-build cash margins are? Is there much of a difference?

The best way I can answer that question is just to let you know that we have seen pricing, and therefore margins, move up across all the rig classes again in the third quarter. As we renew contracts, we expect that pricing will continue to move up on these contract renewals as well, as they come up. We're just -- we're not seeing rigs come on to the market for ourselves [ph]. We are still at close to 99% utilization. John M. Daniel - Simmons & Company International, Research Division: But I guess -- and I gather that's in the comments. But when -- is a customer today willing to pay the similar rate on a rig that's maybe 3 years, 4 years old and probably every bit as good, versus something that's being newly constructed?

The answer is yes. I mean, when an APEX is rolling off, we see upward movement on that contract price. John M. Daniel - Simmons & Company International, Research Division: Okay. Cool. And then the last one from me, just -- once you take delivery of the spreads in Q1, Q2, do you envision ordering anymore frac equipment for the back half of the year?

It's hard to say what will happen in the second half of 2015 with regards to our orders and our situation. We've got to digest the acquisitions that we have, ramp up the utilization there and make sure everything is going okay and, with the other 2 spreads we're going to activate. So we -- I'd say, right now, we just don't have that visibility.

Our next question comes from Jim Wicklund with Crédit Suisse. James Knowlton Wicklund - Crédit Suisse AG, Research Division: We never see downturns coming. We're always the last ones to know -- the pressure pumping market a couple of years ago. And so I appreciate that nobody has cut activity yet. Your customers are still setting their budgets. But the reality is, with oil prices down 20%, depending on how long they stay here, activity in '15 may very well be impacted. And, Andy, you mentioned that it could happen, and you're aware of it. I'm just curious, what are you guys doing to stay nimble on what might happen in '15? I understand that you're not going to start closing down, shutting down, customers are still calling up. But I mean, what are you doing internally to be ready for a weakness in demand in '15, weakness in cash flows, spending, in '15, if it happens?

Jim, it's kind of interesting that you asked that question, because, as you know, a large part of this management team has been at work here for quite a long time. And during that kind of almost 20 years we've been doing this, we've been through a few ups and downs. And so regardless of which direction it's going, I think we have had a fair amount of experience with it. And as I think your favorite expression is, "it isn't our first rodeo." That said, right now we don't see the signs of a change in direction. We recognize the change in oil prices, but we don't see a change in direction in our customer's behavior. That said, we have a strong balance sheet, and we've been able to, I think, adjust quickly and nimbly to things that have happened in the past. And so I think we will this time, if it happens. But that's not what we see right now. James Knowlton Wicklund - Crédit Suisse AG, Research Division: Okay. And pressure pumping, you guys -- like Andy said, you all have a couple of spreads on order. You've bought a couple of spreads. One would think that with the current oil price outlook, that 2015 would be a much more conducive market to consolidation -- Mark your point about the balance sheet -- rather than new equipment. Do you have a preference, understanding of course that whichever is the best deal you'll do, but do you have a preference as we go into '15 as to where you spend your capital?

I think the best indication, Jim, of how we look at it is the fact that we, A, we bought 3 spreads in terms of -- in the new market and at the same time, have been -- have done 2 acquisitions. And that really -- that -- those 2, the acquisition of new equipment plus the acquisitions of existing equipment tell you that, what we see is opportunities, and what we're looking for is opportunities. But for us, these are customer-driven opportunities. We believe that we have the customers for the equipment that we're acquiring . And that's really, I think, the most important distinction between how Patterson approaches some of these transactions versus [ph] the way some others do. We are buying because our existing customers have a demand for incremental equipment, and we believe that we can provided it to them. In the case of non-new equipment, we have to be very satisfied that the equipment is of the same high quality as our existing equipment and can be put to work and has low hours and low usage and all the kinds of things that we would care about. And then, additionally, we feel, in terms of the acquisitions, we obtained valuable facilities, some excellent people and some extremely large opportunities that come with it. And so that's what made those attractive to us.

Our next question comes from Brad Handler with Jefferies.

I always appreciate how you guys give us some interesting information on pumping related to the number of jobs and your revenue per job. And it shows that there is a lot of variability within that from a quarter-to-quarter standpoint. So I appreciate that as I ask the couple of questions that I'm asking. I guess, it does seem like the job count went up, and the job size might have gotten smaller in the third quarter. So I'd appreciate some comments on that, please, if there's anything you can observe in it? And then maybe more generally, can we talk a little bit about some of the trends as you see them developing? There is a lot of talk around condensing of horsepower into larger fleets to accommodate larger job sizes, for example. And I guess, I'm curious if you expect that to happen through the course of the next 18 months, say?

So good questions. When it comes to the job count we publish, there's several moving pieces that are still in that job count. You got variation in stages, variations in chemistry, variations in proppant. And some customers we provide the sands, some customers bring their own sand. And so, those things kind of move around and sometimes from quarter-to-quarter. And so it makes it difficult sometimes to look at revenue per job because you got a lot of moving pieces within that job count. So we acknowledge that there is variations in there, but it's been a historical count that we've been able to give and something that we can continue to give you consistently for some kind of comparison there. When we look at the types of jobs we're doing, certainly in 2014 we've seen increases in sand concentration that we've been pumping. You have seen the shift in West Texas from vertical to more horizontal. We had to add horsepower to crews to be able to handle that. And that explains some of our horsepower orders in total, where you see it's really more horsepower than just 3 spreads that we're bringing on of new equipment. So there are a lot of things that are happening there in our particular business for pressure pumping, as we've transitioned and brought ourselves up to that level of where we're doing 24-hour operations now represents over 90% of the revenue. That shows you the quality work that we're doing. It also shows you the quality of the customer base that we're working for that has that amount of inventory in front of them that can keep us that busy at that level.

Sure. So -- Right. So the trend -- you're moving -- in some ways you're doing what others are also doing as that work gets bigger. Do you expect that to continue? Do you expect that we'll wind up hearing about effectively cutting up a crew to make some other crews bigger because that's the way the Permian is developing? Or that's the way the Marcellus continues to develop? Or do you think things stabilize? Or do you have any window into that at all yet?

The trend through 2014 has been more horsepower per spread because you've had some of our crews shift from doing vertical to horizontal, and we've just added more pumps and more horsepower and more -- a few more individuals into that spread to manage that. I think, there is still some shift in West Texas from vertical to horizontal. There is still some vertical that will continue there as well. When you see those shifts on average, you'll see more horsepower per spread. But I think if you look at individual horizontal jobs that we're doing, you're seeing higher sand concentrations in some places but it's not necessarily driving more horsepower in those individual spreads.

Okay. So that's static. Can you just comment on what redundant horsepower you might need to bring to the site to accommodate more 24-hour work? Or has that also not driven an increase in... [indiscernible]

As you do more 24-hour work, you just have a few more pumps in the system that you can manage on rotation. So you need the ability to be able to take pumps back to maintenance and then rotate them into the fleet. So I think everybody has that same challenge when it comes to their horsepower management. You've got designated horsepower that equals the spread, and you've got a little bit of extra horsepower that you're rotating through maintenance.

Our next question comes from Scott Gruber with Citi.

Excuse me if someone asked this question. But are there material refurb costs associated with the new pumps you purchased? I'm just curious as to the effective price paid for that equipment.

No, all these pumps are in working condition, and all these pumps are actually doing work. We've already started deploying crews out. So this is all active, functional equipment. Remember, we've talked about it a little bit in press release that this equipment is in relatively new condition. It was ordered in 2011 and 2012, and then all received basically in 2012 on this recent acquisition. And it just didn't get a lot of hours over the last couple of years relative to the age of the pumps.

That's good news. And then an unrelated follow-up, as you've high-graded your fleet, how has your customer mix changed over time? And in particular, how is your exposure to private E&Ps evolved over the past 5 years or so?

I'd say the shift for us has been where over the last few years we are doing more work for the larger international oil companies. And it's really increased the breadth of our customer base. We still have work for some of the smaller customers that are out there but we're doing work for more of the bigger customers that are out there too. So it's -- I'm very pleased with the breadth of the customer base that we have. I think relative to others it's probably the strongest out there.

I would just add one small additional thought. I don't know that we work for that many smaller companies. We work for large private companies and large public companies. And the private companies these days are substantial enterprises with substantial balance sheets. They are not necessarily as easily in your eye because of their being private but they are large companies.

And so we... [indiscernible]

That customer mix has gotten broader in the sense of some of the majors. And we've expanded into that, some of the very, very large super [ph] independent public companies.

And so the Wall Street community, obviously, has a lot of access to the public companies. You mentioned no change in tone from your customer base. And that's irrespective of whether they're public or private? It's the same discussion?

It's the same discussion, yes. No change in tone.

[Operator Instructions] Our next question comes from Angie Sedita with UBS.

So Andy, I missed the beginning of the call, so I apologize if you did talk on this, and I know you spoke to the land rigs and what's under contract. So the capacity that you're adding on the pressure pumping side, what kind of contract terms are you seeing for that new capacity that you're adding and that you've acquired [ph] as well as the new builds? And could you talk about contracting overall for your pressure pumping fleet? And how easy or difficult would it be to exit some of those maybe pre-existing contracts if things do continue to soften?

All the contracts that we have today in pressure pumping are essentially agreements around pricing, around scope of work, and some of them have periods of term associated with them. Many of these contracts also have 30-day out clauses. So we're certainly not locked in, in any way. For a lot of these contracts that we have for new equipment that's coming out, it's going to be accretive to margin. We see pricing continuing to go up into 2015. We wouldn't have made those asset-type purchases if we didn't think it was accretive to margin. And so we think we're in a good position in this space where pricing will continue to push up in 2015, and we are not locked into contracts in ways where we can't take advantage of them.

Okay. That's helpful. And then as you know and as you mentioned, construction -- new construction on the new-build land side is a concern of the market. Are you -- you're obviously seeing great demand on the APEX rigs, as you highlighted. Are you seeing any behavior by your peers where you have concerns on their actions, where they're focusing on adding new builds merely for the sake of adding new builds versus fairly supplying the market with new builds that have demand at fair rates?

So far what we're seeing in the market is that we are able to go out there with a great product in the APEX rig, and into 2015 we've been able to push up leading edge pricing. We think that's still has room to continue. So that gives us an indication that others are doing similar because we're able to push up pricing as going forward into 2015. So we don't have necessarily have direct views of what everybody is doing, but certainly, relatively speaking, with the market looking like that, I think the market is still in good shape for us.

Okay. And then finally, you mentioned the payback at roughly 4 years. Is there an opportunity to lower that payback return to a period closer to 3x on either the cost of the rigs or other efficiency factors?

We certainly have initiatives underway. We don't speak about them a lot, but we think we'll continue to drive a bit of costs out of the system when it comes to our capital spend. And we think that pricing will continue to move up in 2015. We'll just have to wait and see how that plays out in total.

We have a follow-up question from John Daniel with Simmons & Company. John M. Daniel - Simmons & Company International, Research Division: Just a couple for you. On the 2015 CapEx spend, I know you don't have a formal budget laid out yet, but back of the envelope math suggests something in the $1.3 billion range, if not higher, if the cadence persists throughout the year. Is that a reasonable supposition on my part?

John, we haven't done our budget for 2015 yet. I'm guessing here, I didn't try to repeat your math, I'm guessing here we talked through 3 quarters and you're extrapolating out. We have not looked into the fourth quarter of 2015 yet. John M. Daniel - Simmons & Company International, Research Division: Okay. Fair enough. On the 2 new spreads, do you have the customers lined up already?

The 2 new spreads that are being activated in 2015. So, yes. So one is under contract, the other is certainly in the final stages of discussion, but we know who the customers are. John M. Daniel - Simmons & Company International, Research Division: Do you know if those customers, if they're adding an incremental fleet or if they're displacing an existing provider?

It's kind of hard to say. I think, one is definitely additional fleet, not sure about the other one. John M. Daniel - Simmons & Company International, Research Division: Okay. And then the last one from me, when your rigs have been rolling off contract, what percent of them -- of the customers retained that rig? Ballpark.

Considering, especially with the APEX, considering the APEX rig utilization hasn't really moved, and it's still near 99%, that tells you that almost every customer is holding on to these rigs. John M. Daniel - Simmons & Company International, Research Division: [indiscernible] Okay. [indiscernible]

We get calls still asking about APEX availability in the fourth quarter. But with our utilization, we just can't manage that right now. We're essentially sold out of APEX through the middle of next year.

Our next question comes from Mike Breard with Hodges Capital.

What percentage of the wells that you drill in Texas do you get the frac-ing work? In other words, is there any synergy there?

There is not necessarily direct synergy from following a rig that we used on drilling the well with the pressure pumping. We operate really kind of 2 different spaces. And even with the customer, they are contracted with different divisions at the E&P's office. But there are certainly some other synergies out there. For instance, we get a lot of marketing intelligence. We know where the rigs are going a year in advance. It certainly gives us an indicator of which basins are going to be active on the completion side.

At this time, we have no further questions. I will now turn the call back over to management for closing remarks. Please proceed.

I'd like to thank all of the investors and analysts for joining us and look forward to speaking with you in February respecting our fourth quarter 2014 results and year-end earnings. Thanks, everybody.

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