Patterson-UTI Energy Inc (PTEN) 2014 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the third quarter 2014 Patterson-UTI Energy Incorporated earnings conference call. My name is Denise and I'll be the operator for today. At this time, all participants are in listen-only mode. Later we will conduct a question-and-answer session.

(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 three and nine 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 as statements made in this conference call that state the Company's or management plans, intentions, beliefs, expectations or predictions for the future are forward-looking statements within the meaning of the US 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 will 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 non-cash 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 non-cash charge of $77.9 million, or $0.36 per share after tax, related to the Company's mechanically powered rig fleet. This non-cash 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 fleet.

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 four quarters. The cash flow from the active mechanical rigs is helping to fund the Company's new APEX rig manufacturing program.

As our rig fleet continues to align -- to evolve -- our rig fleet continues to evolve as we align our fleet with customer demand. This month we reached a milestone surpassing 100 rigs equipped with walking systems, which we believe to be the superior system for pad drilling. Demand for APEX rigs continues to be strong. We are pleased with the large number of rigs we have under term contract and expect this trend to continue. In response to strong customer demand, we are raising our rig manufacturing capacity as we are effectively sold out of new APEX rigs through the middle of 2015.

As announced earlier this week, we completed our second pressure pumping acquisition of the year, adding 148,250 frac horsepower to our fleet. Collectively, the two acquisitions added approximately 180,000 frac horsepower to our fleet and provided us with three new facilities to support our operations in east and south Texas. In total, we paid $176 million for these acquisitions. This represents less than $1,000 per horsepower. In addition, we received inventory and took over lease facilities.

We have fundamentally changed our Company through the transformation of our rig fleet and the substantial increase in our pressure pumping horsepower. Our rig fleet continues to evolve as we align our fleet request customer demand and focus on modern, highly efficient APEX rigs with a preponderance of our rig fleet now under term contract. In pressure pumping, our fleet consists of the latest technology, high horsepower pumps, and has increased by more than 500% during the last five years to 1 million-horsepower.

With that I'll turn the call over to Andy.

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 US 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 US 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 US 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 day rate 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 seven contracts for new APEX rigs. Further to this, and in response to strong customer demand, we are raising our manufacturing rate and now expect to complete 30 new APEX rigs during the four quarters ending September 2015, including six in the fourth quarter and approximately eight per quarter in the first three quarters of 2015. Of these 30 new APEX rigs to be completed, 22 are currently contracted.

We are keenly aware of investor concern that the number of new land rigs to be delivered next year across the industry may oversupply the market. However, instead of building to a theoretical capacity, we are building to what we believe to be ongoing market demand. All new APEX rigs go out under term contract and we are essentially sold out through the middle of 2015. Additionally, we are confident that we will contract the remaining new APEX rigs still available. Furthermore, we have no indications that any of our new-builds will replace any of the existing rigs in our fleet. In general, the multi-year projects where customers are contracting our new APEX rigs are not the same as the shorter programs where they are contracting our legacy rigs. We are proud of the breadth of our customer base and our ability to provide different technologies for their various projects.

Turning now to pressure pumping. We generated record quarterly revenues of $349 million from pressure pumping during the third quarter, a sequential increase of $42 million due to higher activity levels and the full quarter impact of our June acquisition. We are pleased that in the third quarter we generated more than 90% of our frac revenue from 24 hour operations. We still see opportunity to improve utilization by reducing the [white] space in our schedule.

During the quarter, we incurred higher costs related to sand transportation and equipment maintenance. We also had start-up costs and crew activations associated with our June acquisition and a new frac spread that started in early October. At the end of the third quarter, late September flooding in the Permian Basin negatively impacted revenue, increased costs, with sand demurrage and crews that were still being paid to manage equipment on suspended jobs. As a result of these factors, our pressure pumping EBITDA increased by $3.3 million during the quarter to $62.8 million, which was a smaller than expected increase.

Since the end of the quarter, we have activated the first of the three previously announced frac spreads on order. Additionally, as announced earlier this week, we completed the acquisition of 148,250 frac horsepower, bringing our total fleet to more than 1 million-horsepower, including approximately 918,000 of frac horsepower. We are very excited about the two acquisitions that we have made since mid-June. Along with the additional horsepower, we are adding skilled people that are working from three new locations, which gives us improved coverage across south and east Texas. On behalf of our management team, we would like to welcome these new employees to Patterson-UTI.

Along with the acquisitions, we have two additional spreads on order. One of which will be activated during the middle of the first quarter in Texas and the other will be activated during the middle of the second quarter in the northeast. Upon delivery of these two fleets, we expect to have more than 1 million-horsepower of hydraulic frac capacity by mid-2015. Looking forward, based on our customers' current schedules, we expect fourth quarter pressure pumping revenues to increase approximately 10% sequentially.

Gross margin as a percentage of revenues is expected to improve to 21%. Our revenue projection for the fourth quarter includes cost recovery pricing for logistics costs and typical fourth-quarter seasonality. As well, our projection includes costs for ramping up utilization of our recently acquired horsepower and start-up and activation for the next new frac spreads to be deployed in the first quarter of 2015.

Before moving on, I would like to acknowledge that today is an important anniversary in the pressure pumping history of our Company and for the energy history of the United States. 10 years ago today our pressure pumping team in the northeast completed the very first modern Marcellus shale well. Over the past 10 years we have gathered significant amount of experience in fracking unconventional wells in Texas as well as the northeast. That same innovation that led us to be a pioneer in fracking the Marcellus is still alive today as we are a leader in bi-fuel frac technology, using natural gas as a fuel source. We continue focus on differentiating ourselves in this business through excellent well site execution, applied 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. Depreciation expense during the fourth quarter is expected to be $164 million. SG&A during the fourth quarter is expected to be $19.5 million. We expect our effective tax rate to be approximately 32.5% in 2014.

And with that, I will now turn the call back to Mark for his concluding remarks.

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'd like to both commend and thank the hard working men and women who make up this Company. 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 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 Schumacher with KeyBanc Capital Markets. Please proceed.

Thank you. Andy, I was wondering if you could just 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.

Thanks, Robin. Good morning. 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 US. As you've seen in our filings, we have an investment with a mine as well. 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 require at the same time going forward in the new horsepower 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 they were and we didn't have sand, we wouldn't have incurred the demurrage cost and our margin would have been a little bit higher.

Okay. 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 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 2015, but would you expect on your rollover strategy that you would be able to come close to 70% through 2015?

We're not seeing any change in the trends when it comes to contracting other than the continued push on pricing. We see that as contracts roll, 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. Or 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.

Okay. Great. Thanks a lot, Andy.

Our next question comes from Doug Becker with Bank of America-Merrill Lynch. Please proceed. Mr. Becker, your line is actually open.

Our next question comes from Jim Rollyson with Raymond James. Please proceed.

Good morning, gentlemen.

Good morning.

Andy, you sound pretty confident in the -- when you went through your prepared remarks about getting rigs out. I think you've got, what, eight rigs that aren't spoken for officially but 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 next year, do you think?

We're constantly in discussions with customers and even over the last month we haven't seen any change in flow of customers who have 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.

Okay. And these are still predominantly in the three-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, the average is very close to three years. Any rig that we contracted for less than three 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.

That's great to hear. On the frac side, you guys have closed two 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 the two acquisitions. We did the one in June. We just closed the other one just here a couple weeks ago. 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 two more fleets that we'll 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're just going to work through what we have right now and it's looking gored for good for us with this increased level of horsepower going into 2015.

Great. Appreciate the color.

Our next question come Dave Wilson with Howard Weil. Please proceed.

Good morning, gentlemen. Thanks for taking my question. 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've 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're 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's 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're 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.

Great. Thanks, Andy, for the additional color. I'll turn the call back over.

Our next question comes from James West with ISI. Please proceed.

Good morning, guys.

Hi, James.

Andy, as you think about your you new-build cadence, I'm pleased to see you moving that up to eight a quarter, what is your constraint on moving that higher from here? I'm assuming its 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're very cautious about the market. We're 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 kind of (inaudible) --

Did we lose you?

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

Over the past couple years the paybacks were in the four to five range. But if you look at what we're contracting into 2015, it's much closer to that four year range.

Okay. Got you. Thanks, Andy.

Thanks.

Our next question comes from Byron Pope with Tudor Pickering. Please proceed.

Good morning, guys. 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 you think about the two 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.

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 two incremental spreads will be on similar type work?

Sure, that will likely continue at those levels.

Okay. And then as you think about the pressure pumping business when you're already 90% on 24 hour operations, could you speak to maybe one or two sorts of examples as to how you could further eliminate white space in the frac calendar?

Yes and 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's still some white space to fill out in the calendar. When you go out to a pad and you work for six, seven 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 the system when it comes to managing our calendar, especially across Texas. So we certainly that as we have seen going through 2014, we've seen this increase in utilization. We've seen white space come out of the calendar. We think we'll continue to see that's as we move into 2015 as well.

That's helpful. Thanks, guys.

Our next question comes from Jason Wangler with Wunderlich Securities. Please proceed.

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

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're only projecting around 21%. There's a mixture of seasonality in that. There's the cost 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. Happy to respond to that question. We're constantly trying to evaluate whether it's an appropriate time to use capital to buy back shares. Frankly, we always consider it, 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 all always on our plate.

Appreciate it. Thank you.

Our next question comes from John Daniel with Simmons & Company. Please proceed.

Hi. Good morning, guys.

Good morning.

Want to start with a housekeeping item for John. What will you use for the 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 will also provide information about the remaining life. When we receive that, we'll finalize the recording of those transactions and their depreciable lives. That will occur in the fourth quarter.

Okay. So not ready to give a number yet for the year?

No, the work's not completed.

Okay. That's fine. Just wanted to dig into the contract coverage for a second. In 2015 you have got the 93 rigs under contract. Presumably that includes the 22 of the 30 rigs being built. Is that right?

That's correct.

Okay. Are any of the mechanical rigs under contract or is that all spot?

No. We have mechanical rigs under term contract as well.

Okay.

When you have the level of upgrades that we have on some of these rigs, they're still very popular rigs in some places.

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 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've seen pricing, and therefore margins, move up across all the rigs 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 onto the market for ourselves. We're still at close to 99% utilization.

I guess -- 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 three years, four years old and probably every bit as good, versus something that's being newly constructed?

The answer is, yes. When an APEX is rolling off, we see upward movement on that contract pricing.

Okay. Cool. And then the last one from me, once you take delivery of the spreads in Q1, Q2, do you envision ordering any more 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's going okay and with the other two spreads we're going to activate. I'd say right now we just don't have that visibility.

Okay. Thank you very much.

Our next question comes from Jim Wicklund with Credit Suisse. Please proceed.

Good morning, guys.

Hey, Jim.

We never see downturns coming. We're always the last ones to know -- the pressure pumping market a couple 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 2015 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 2015? I understand that you're not going to start closing down, shutting down, customers are still calling up. What are you doing internally to be ready for a weakness in demand in 2015, weakness in cash flows, spending in 2015, if it happens?

Jim, it's kind of interesting that you ask 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've 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 customers' 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.

Okay. And pressure pumping, you guys -- like Andy said, you all have a couple 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 2015 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 three spreads in terms of -- in the new market and at the same time have been -- have done two acquisitions. And that really -- those two -- the acquisition of new equipment, plus the acquisitions of existing equipment, tell you that what we see is opportunities. 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 and the way some others do. We're buying because our existing customers have a demand for incremental equipment and we believe that we can provide 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. So that's what made those attractive to us.

Points well made. Thank you very much, Mark. Thanks, Andy.

Our next question comes from Brad Handler with Jefferies. Please proceed.

Thanks, guys. Good morning.

Good morning.

I always appreciate you 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's a lot of variability within that from a quarter-to-quarter standpoint. So I appreciate that as I ask a couple 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's 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 published, 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 sand, some customers bring their own sand. 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've got a lot of moving pieces within that job count. So we acknowledge that there's 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 concentrations that we've been pumping. You've seen the shift in west Texas from vertical to more horizontal and we've 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 hours power than just three spreads that we're brining on of new equipment. So there's 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's still some shift in west Texas from vertical to horizontal. There's 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.

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 is that also not driven an increase in --

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 extra horsepower that you're rotating through maintenance.

Got it. Thank you, guys.

Thanks.

Our next question comes from Scott Gruber with Citi. Please proceed.

Good morning.

Hi, Scott.

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.

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 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's your customer mix changed over time? And in particular, how is your exposure to private E&P's evolved over the past five years or so?

I'd say the shift for us has been where over the last few years we're 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're not necessarily as easily in your eye because of their being private, but they're large companies. And I would just say that -- that customer mix has gotten broader in the sense of some of the majors -- we've expanded into that -- some of the very, very large super independent public companies.

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. That's irrespective of whether they're public or private. It's the same discussion?

Same discussion, yes. No change in tone.

Okay. Great. Thanks.

(Operator Instructions)

Our next question comes from Angie Sedita with UBS. Please proceed.

Thanks. Good morning, guys.

Good morning.

Andy, I missed the beginning of the call so I apologize if you did talk on this and I know you spoke 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 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 (inaudible) 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're not locked into contracts in ways where we can't take advantage of that.

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 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're 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 still has room to continue. So that gives us an indication that others are doing similar because we're able to push up pricing going forward into 2015. So we don't have -- necessarily have direct views of what everybody's 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 four years. Is there an opportunity to lower that payback return to a period closer to three times on either the cost of the rigs or other efficiency factors?

We certainly have initiatives under way. And we don't speak about them a lot. But we think we'll continue to drive a bit of cost 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.

All right. Thanks. I'll turn it over.

We have a follow-up question from John Daniel with Simmons & Company. Please proceed.

Thanks for putting me back in, guys. 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 three quarters and you're extrapolating out. We have not looked into the fourth quarter of 2015 yet.

Okay. Fair enough. On the two new spreads, do you have the customers lined up already?

The two 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.

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.

Okay. And then the last one from me, when your rigs are 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 onto these rigs. 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.

Okay. That's all I had. Thanks a lot, guys.

Our next question comes from Mark [Buede] with [Hughes] Capital. Please proceed.

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

There's not necessarily direct synergy from following a rig that we use on drilling the well with the pressure pumping. We operate really two different spaces. And even with the customer, they're contracted with different divisions and the EMP's office. But there's 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. And it certainly gives us an indicator of which basins are going to be active on the completion side.

Okay. Thank you.

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 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.