Good day, ladies and gentlemen and welcome to the Second Quarter 2017 Patterson-UTI Energy Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we'll conduct a question-and-answer session and instructions will follow at that time. As a reminder, this call is being recorded. I would now like to introduce your host for today's conference, Mr. Mike Drickamer. Sir, you may begin.

Thank you, Scarlett. Good morning. And on behalf of Patterson-UTI Energy, I'd like to welcome you to today's call to discuss results for the three months and six months ended June 30, 2017. Participating in today's call will be Mark Siegel, Chairman; Andy Hendricks; Chief Executive Officer; and John Vollmer, Chief Financial Officer. 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 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 second quarter of 2017. 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 before turning the call over to Andy Hendricks, who will share some comments on our operational highlights as well as our outlook. After Andy's comments, I will provide some closing remarks before turning the call over to questions. Turning now to the second quarter, as set forth in our earnings press release issued this morning, we reported a net loss of $92.2 million or $0.46 per share on revenues of $579 million. Total adjusted EBITDA during the second quarter was $79.2 million. The financial results for the second quarter include pre-tax merger and integration expenses and impairment charges totaling $80.2 million. Excluding the expenses and charges, the net loss per diluted share would have been $0.21. These charges include $51.2 million of merger and integration related expenses and $29 million of noncash impairment charges from the write-down of drilling equipment related to the upgrade of certain rigs to super-spec capability. Andy will provide further details as to our super-spec upgrade plans. Our balance sheet remains strong, with debt to total capital ratio of 16.5% at June 30. The second quarter was transformative – was a transformative quarter for us. We closed the merger with Seventy Seven Energy on April 20, which strengthened our position in both contract drilling and pressure pumping and added a new line of business for us in oil field rentals. Including the contribution from Seventy Seven Energy, compared to the first quarter, total revenues and adjusted EBITDA, excluding merger and integration expenses, both increased by 90%. I am pleased that during the…

Thanks, Mark. As Mark mentioned, the second quarter was a transformative quarter for Patterson-UTI. We closed the merger on April 20, and therefore financial results for the second quarter include 71 days of contribution from Seventy Seven Energy. The consolidation of Seventy Seven Energy affected the financial and operational metrics that we typically discuss due to various factors, which I will describe in a moment. For purposes of comparison, we will compare reported second quarter results with those from the first quarter where Q1 reflected Patterson-UTI as a standalone company. In Contract Drilling, demand for high-spec rigs remained strong despite moderating oil prices during the second quarter. Our average rig count in the U.S. was 145 rigs. On a standalone basis, Patterson-UTI averaged 100 rigs in the U.S. during the second quarter, up 23% from 81 rigs for the first quarter. In Canada, our average rig count for the second quarter was one rig, down from two rigs in the first quarter. During the second quarter, average rig margin per day was relatively flat at $6,710 per day compared to $6,750 per day in the first quarter. Despite the relatively flat margins, there were many moving pieces that affected average rig revenue and operating costs on a per-day basis. First, rig pricing improved during the second quarter, but was offset by the repricing of certain rigs rolling off legacy long-term contracts and an increase in the proportion of rigs on reduced standby rates that resulted from the merger with Seventy Seven Energy. Accordingly, average rig revenue per day deceased $930 per day to $20,270 for the second quarter. This decrease in average rig revenue per day was largely offset by an $890 decrease in average rig operating cost per day to $13,560. Average rig operating costs on a per day…

Thanks, Andy. To risk stating the obvious, there's considerable pessimism concerning oil prices and the state of the oil markets. Optimism in late 2016 and early 2017 arising from oil prices above $50 per barrel has turned to pessimism, as oil briefly touched below $43 per barrel in June. A consensus appears to have arisen among analysts and investors that oil and natural gas prices will be lower for longer. In other words, the consensus is that commodity prices will not be meaningfully higher in the second half of 2017 and maybe not even in 2018. Against this backdrop, what's happening for Patterson-UTI? First, by and large, we have not seen our customers decide to drop rigs. And in fact, based on contracts we have already signed, we expect to see our rig count increase slightly over the next few months. Although the rate of increase in the second half is not likely to approach the rate of increase in the first half of 2017, we don't see an impending decline in drilling activity by our customers. Put simply, the technology advances in drilling have made it economical for E&Ps to continue to be active, even in a $45 per barrel to $50 per barrel oil market. The staggering development of advanced rig technology is now often taken for granted. For that reason, I think a few words about those developments are warranted. Some of the technology advances, such as walking systems, no longer seem cutting edge but continue to have a profound impact on efficiency. The continuing adoption of multi-well pad drilling is reducing non-productive time by allowing a rig to move from well to well in 45 minutes, as compared to multiple days when moving between single-well pads. Additionally, as walking systems offer greater flexibility in the way…

And our first question comes from Marshall Adkins with Raymond James. Your line is now open. J. Marshall Adkins - Raymond James & Associates, Inc.: Mark, thank you for recognizing that there are at least one of us still out there thinking oil moves higher. And in that vein, I'd like to get a little more insight into the remaining frac fleet that has not been upgraded and reactivated. Best I can tell you, maybe you have another 300,000 that you could upgrade, Andy, next year. If oil does participate and move higher, what are your plans for that and how much will it cost per fleet? I'm assuming the cost, as you get further into the inventory, keeps going higher per fleet. But give us some sense of your thoughts there as well as the cost to do that.

Yes. Thanks. Good morning. So, let me back up a little bit in the story. You know right now we see the rig count essentially flat to slightly up in the U.S. market. But pressure pumping activity has been lagging rig count all year long. And so, we still have the opportunity to continue to activate more spreads this year. By the end of this year, we will have activated 23 spreads total, active, and that's going to be over 80% utilization for us. So, you know, just given the math, we still have a number of spreads that we can activate in 2018. And so, if rig count continues on track the way we see it at today's commodity price, we think we're going to be very busy in pressure pumping. I think the key is, whether or not we activate any more spreads in 2018, we're over 80% now. And I think the industry is going to be in that same range. And when the industry is at 80%, it really starts to tighten things up in terms of availability for crews at certain times. It tightens the schedule for everybody. And that's when it really starts to drive the pricing as well. And we saw that back in 2014. J. Marshall Adkins - Raymond James & Associates, Inc.: Right. So, back – so how much is it going to cost for the additional capacity to bring it back out?

So, when we were originally reactivating spreads last year, our earlier spreads were in the $2 million range. As we work through the fleet, we get into $3 million. I think the additional spreads of the three that we'll activate this year and anything into 2018 would cost us in the $4 million to $5 million range per spread. J. Marshall Adkins - Raymond James & Associates, Inc.: Perfect. Makes sense. All right. You guys seem to have done meaningfully better than most of your peers, both in terms of revenue improvement, but also margin improvement on both sides of your business. How much of that was due to the Seventy Seven Energy integration? And can you give us some thoughts on that – how that integration's coming? Have there been any surprises? It seems like, from looking at the outside, it's gone extremely well and that helped to contribute to your outperformance. But just give us some color on that if you would.

Sure. We closed that merger back in April. And we really had less than a month towards the end of the quarter to do a lot of reconciliation and take a deep dive into operations, financial numbers and things like that. At the same time, there was a lot of work being done to start to prepare for the transition to really fully integrate such things as back office. So, on July 1 for instance, we went live with all systems on the same ERP. We transitioned from the previous SAP system that they had and got everybody on Oracle. In July, we were able to migrate all the employees over to the same payroll system. All the legal entities were moved for the July 1 when the ERPs was put in place. So there's been a lot of work and a lot of heavy lifting by a lot of people across the company. And so, I want to commend everybody for all the efforts and all the time that everybody put in. So, there's been a lot of work in the back office. At the same time, we've announced the leadership positions for the different businesses, leadership teams. So a lot of work that's been going on there. Supply chain's been working to integrate things. So we believe that we are on track for what we've previously discussed as a $50 million in synergies on an annualized basis. And we have visibility on the majority of those synergies today. J. Marshall Adkins - Raymond James & Associates, Inc.: Thank you all.

And our next question comes from Chase Mulvehill with Wolfe Research. Your line is now open.

Hey. Good morning.

Morning.

I guess the first question, I just kind of wanted to come back to the centralized logistics center. And then maybe just kind of help us understand how accretive and how helpful that was to the pressure pumping business in 2Q. And then as we go forward, how much you think that this can continue to add to margins as we go forward?

Well, without getting into the details of some of the numbers behind the benefits, and I'll give you some general qualitative analysis of what's happening. So, as we work through the process to centralize logistics, and on a previous call, we said that we were already running all of Texas from the centralized logistics center. And today we're working to move the Mid-Continent operations into that, and before the end of the year, we'll be getting the Northeast into the same center. So, the real efficiency there is the ability to move trucks to locations and just maximize the amount of time that the trucks are spending moving the sand and just managing the overall efficiency. Some of these are our own trucks, some of these are third-party trucks. We're also paying attention to where railcars are. And so, there's just a lot of work there to make sure that we're very efficient on how sand moves to the well site and that we're minimizing any of the demurrage costs. And so, when we were managing in the regions, it was manageable up until about last year when sand volumes per well just started to move to the levels that they are today. And then once you're pumping full unit trains, if you're not careful and you're not watching what's going on, on a 24/7 basis, you can have trucks that aren't rolling and you could incur demurrage costs in various places without even knowing it. So, this gives us that level of efficiency to get the costs down. It also makes us relatively popular with the trucking companies because they can be efficient. Trucking companies want to move trucks, and we can help them do that. And so, in some basins, we've become a preferred partner for some of these trucking companies to work with. So very pleased with the results we're getting in general.

Okay. All right. Thanks for that. And I guess one last one. On the SCR rigs that you have, are you planning to upgrade any of the APEX SCR rigs to AC rigs, or is it just the 1,000 horsepower rigs that you're upgrading?

So, the rigs that we are upgrading are APEX 1000s, and we're taking these up to APEX-XK 1500s, as we talked about today. And that's what we have planned right now and we'll fill you in at the next earnings call on any future change to that. But suffice it to say, the demand for super-spec rigs in the market is still strong. We have all of them working except for one, which is in a basin that's a little bit off the beaten path away from the Permian. But right now, we really need to get some more super-spec rigs in our fleet just to meet the requests from our own customers today. And so that's what we're doing and that's why we're working through upgrade process.

Okay. I'll turn it back over. Thanks, Andy.

Thanks.

And our next question comes from Scott Gruber with Citigroup. Your line is now open.

Good morning. Great quarter, especially given all the moving pieces.

Thank you.

Andy, you mentioned the improvement in stages per day that the legacy Patterson frac fleet's achieving. Is there a gap in stages per day that the legacy Patterson fleet and the legacy Seventy Seven fleet are achieving and is this an area that you can exploit for improvement down the road?

No. The only reason that we called that out in terms of legacy Patterson-UTI is, we have the data. We have the historicals. So, that was the only way we could make a reference. What we're really trying to show you – and I'm sure that other pressure pumping companies are seeing the same thing. But as the industry shifts more toward multi-well pads, especially in the Permian, the operators can be more efficient and that makes us more efficient. And so, we're getting better returns on our assets to be able to work in that manner. And so that's helping overall margins in general. But no, I wouldn't – there's certainly no difference between how legacy Seventy Seven's working and Patterson is, just because we had the historical data.

Got it. And I'm trying to think about where you could take your pressure pumping margins here. In the absence of any spot price improvement, after you get through your deployment plans, where can you take your gross margin? And I'm thinking about after the reactivation costs with any improvement in asset during that you're able to achieve down in the Permian and elsewhere, cost structure improvements – you are heading toward 21% in 3Q. Where can you take that number after these factors are in the past, but without any other – any further price improvement?

So, as we mentioned, we are projecting to get to at least 21% in the third quarter on a gross margin level. That does include the cost of reactivation on the other spreads that we discussed as well. And that cost is mostly labor. So, it's a big cost at the expense line that start to bring people in. We got over a 100 people on our frac crew and we're going to have them on for a month or more per crew before the crew generates any – or before the spread generates any revenue. As well, it's hard to say what will happen as we get into 2018. But as I mentioned earlier, our utilization's going to be over 80%. And I suspect other pressure pumping companies are going to be over 80% as well. I mean, we're at that level in the industry, it's tight. I mean, it feels tight. When operators are calling, trying to book days on the calendar, it becomes harder to get there on certain days. And it does create this tightness in the market that I think there's potential to move pricing past that point as well. We mentioned a number on the last call, and it's really about the same on this call. About two-thirds of our equipment in pressure pumping is not tied to contracts right now, or not tied to pricing agreements. So, from that respect, I think we do have the ability that if we get some more pricing traction in the market towards the end of this year and into next year, that we still have the ability to move that as well.

And can you remind us when the contracted frac fleets reprice?

You know, there's no waterfall coming. There's just – there's various contracts at various times going out into the future.

Okay. Appreciate the color. I'll turn it back. Thanks.

Sure.

Our next question comes from Jim Wicklund with Credit Suisse. Your line is now open. James Wicklund - Credit Suisse Securities (USA) LLC: Good morning, guys.

Hey, Jim. James Wicklund - Credit Suisse Securities (USA) LLC: Your pressure pumping increase was nothing short of exceptional, so congratulations on that. I'm curious, how much of your pressure pumping revenues were sand revenues? And I ask that because we've heard companies report as much as 60% or so of their pressure pumping revenues are for sand sales. And on the sand that you do buy and mark up and pass along, are your margins better on sand than sheer pumping? Or is it the other way around?

So, we still provide the majority of our customers with sand. And there are of course customers that provide their own. But the majority of our customers, we provide the sand. And I wouldn't say there's been any real shift on a quarter-to-quarter basis in that percentage. In terms of margin on sand, we've seen some cost increases in sand on our side from Q1 to Q2. It's been – it's not been as high as what I've heard reported. For us, from Q1 to Q2, we've seen sand costs increase at a little bit less than 10%. And especially in the Permian it's only been less than 10%. But we still get a margin on that sand. But we still get a higher margin on the service aspect than we do on the sand. And the sand volumes are big. The cash is nice. But the actual margin on the sand is not as high as what we charge on the service itself. James Wicklund - Credit Suisse Securities (USA) LLC: And what – Andy, what percent of your pressure pumping revenues do you think are the sand sales?

Don't have that number in front of me right now. But it hasn't changed quarter to quarter, in general. James Wicklund - Credit Suisse Securities (USA) LLC: Can you – well, we didn't know what it was last quarter. Can you ballpark me? Is it 20%, 50%, 70%? I won't hold you to it.

It's in the range of about 35% to 40%. James Wicklund - Credit Suisse Securities (USA) LLC: 35% to 40%. Okay. Thank you. And my follow-up, if I could, you say there are 465 super-spec rigs out there in the market. You are upgrading seven of your APEX 1000s, upgrading. There are 700 plus horizontal rigs running. Even in a flat rig count, which you clearly don't expect, which is great, but the market will continue to replace these non-super-spec rigs over the next couple years. Where do you get the rigs to do that? Do you have to start getting new builds if you run out of upgrade potential? If we're just – like I say, even if we're churning at a current rig count just swapping out, to your point, the rigs that are out there with super-spec rigs, where do those rigs come from for Patterson?

Right now, we have the upgrade plan that we're working on that we discussed today. There could be some upgrades in the future. I think it's important to note that we don't believe that the market is there for the economics on new builds. And it's just not there today. So, we don't see this wave of new builds coming into the market yet. But we still see the potential to upgrade the rigs. We've chosen to discuss what we're doing now because it's important for the business, important for you to know we're ready, that we're increasing CapEx to do it. But we're getting contracts to do this as well. And so, the economics on these upgrades makes sense. Now, further, more intensive upgrades, it may take more than $8 million. That may materialize before new builds. So, I don't see new builds in the near future. James Wicklund - Credit Suisse Securities (USA) LLC: Okay. Thanks, guys.

Our next question comes from Byron Pope with Tudor, Pickering, Holt. Your line is now open. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc.: Good morning, guys. A question related to the one that Jim just posed, and just wanted to get specific if we could with regard to the incremental of APEX 1000 rigs in your fleet that might be candidates for upgrades to APEX-XKs over time, if the economics warrant.

So, yes, we have other 1,000 horsepower rigs in the fleet that could be potential candidates for an upgrade at some point. Of course, we've chosen to take the ones that make the most economic sense right now. And the economics on the contracts we're getting are good and certainly give us a good payback on the $8 million investment. I think we'll have to wait and see what kind of improvement we see in the market going forward as to whether or not some of the other rigs in the fleet could be candidates. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc.: And is it reasonable to think that you would need the same type of term contract coverage that you've got on the five that you're currently upgrading to make the numbers make sense in an uncertain environment?

We certainly would like to see some kind of commitment from the customer. The rates on these rigs are in the low-20s. So, from an economic standpoint, it does make good sense. So, we want to see similar-type economics in order to proceed with further upgrades. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc.: Okay. And one last question for me on the pressure pumping side. It seems as though you guys have historically done a great job of putting incremental spreads to work for existing customers in your core basins. Is it fair to think that that's the case for the spreads that you're adding in the back half of the year?

Yes. Yes, we expect it to be similar. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc.: Okay. Thanks, guys.

With some potential new customers in the mix as well. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc.: Appreciate it.

The next question is from Sean Meakim with JPMorgan. Your line is now open.

Hey. Good morning.

Good morning.

Let me just follow on a couple things you've already discussed, a couple finer points. I think on the 1,000 horsepower rigs that you're upgrading, can you maybe just walk us through how you think about calculating that payback? So I guess I'm thinking about you're laying out $8 million of capital, you've got a contract of maybe 18 months to 24 months. Is it looking at just the incremental rate versus the other rig or do you take into account, as you talk about, the demand for the 1,000 horsepower rigs are waning, such that perhaps there's a utilization adjustment and so we'll be able to work this asset much better? And how we think about that and where you think the payback would be on these types of rigs, is it – on these capital commitments. Is it three to four years? Is it within that 18 months to 24 months?

So, as we mentioned, the cost to do the upgrades is around $8 million per rig on average. The rates we're getting on these is in the low-20s. So, there's good economics there to get us a payback in about a three-year or four-year period, looking at margins and the rig itself. But we also have to recognize that there's just not a strong market for 1,000 horsepower rigs. The market has evolved. There was a time when an operator might pick a 1,000-horsepower rig because it is a lighter rig, easier to move, quicker to get from pad to pad. But now look what we're doing with XK 1500s. We're moving these rigs in two days or less between pads in West Texas and South Texas. So, operators look at the efficiency that they can get out of a rig like a 1500 XK. And the 1000's just become less interesting. So, this is a very worthwhile investment for us. It extends the life of the rig by another 10 years or so. So, it's certainly a good investment for the long term for the company.

Sean, I would just add one additional thought, which goes as follows. These rigs were originally built looking at the market in the northeast when there were enormous trucking and load restrictions. They were specifically designed for that kind of problem and that kind of need. Those laws were changed. The market in the northeast changed. And for any number of reasons, these rigs, which are basically 10 years old or longer, are no longer the most fit-for-purpose rigs. And we see an opportunity, as Andy said, for approximately $8 million to take a rig that is no longer in high demand and turn it into a rig that is in extremely high demand. Those economics are incredibly worthwhile from our perspective.

So, these rigs will come out of Appalachia. They're going to the Houston yard for upgrades. And they'll find their way over to West Texas.

Got it. No, that makes sense to me. I just think it's helpful to walk through some of the math. So, I appreciate you guys doing that for me. I guess just one more on the Seventy Seven integration. You touched on it, but maybe I was hoping you could get a little bit deeper. Just as you're going through this point, you said good line of sight in terms of hitting the synergy targets. But I guess as you look at the supply chain portion of that, any issues that have arisen and/or opportunities that maybe you didn't know before you got the chance to look under the hood? Just thinking about what that opportunity set could look like within supply chain for Seventy Seven.

There's certainly a lot of cost saving potential. We just – we had a larger company with a larger footprint and a very good supply chain operation and logistics. They did as well. We had stronger negotiating power on a lot of the contracts that we had in place. We were able to roll legacy Seventy Seven purchasing into Patterson-UTI supply chain and there's going to be significant annualized savings from that.

All right. Fair enough. Thank you, guys.

Our next question is from Marc Bianchi with Cowen. Your line is now open. Marc Bianchi - Cowen & Co. LLC: Thank you. Very nice performance and nice guidance as well. I guess where I wanted go was on pressure pumping. If I look at the guidance that you provided for the margin improvement in pressure pumping, appreciate that there's some reactivation costs there in the third quarter, but there was also some in the second quarter. If I try to normalize for that, I still get an incremental that's maybe in the low 30s in terms of percentage. I would have thought that could be better with the tightness in the market and the pricing improvement that we're hearing. Is there anything on the cost side that might be offsetting that? Is it just conservatism? Curious to hear your thoughts around that.

I think it really gets back to the pricing and the market challenges. I mean, you have to think back to where we were on pricing, at the bottom in 2016. Pricing in pressure pumping across the industry had been pushed down 70%, which means to get it back to where it was in 2014 we have to more than double pricing from where we were. So, when you hear about 30% increases and 50% increases in pricing, we have to get it more than double to get back to where we were in 2014 from an actual price-per-stage standpoint. So, where we are in the market today, the industry's probably still a bit short of 80% utilization. There is some tightness in the market, but you're not going to get the wholesale pricing power until we push past that 80% utilization. As I mentioned, once we have 23 spreads deployed, we'll be over 80% and I think the industry will be in the 80% level as well. And I think that's why there is future opportunity for pricing improvements. Marc Bianchi - Cowen & Co. LLC: Okay. Maybe on the cost side, you mentioned the sand cost and not being such a hurdle there. Is there anything else on the cost side that might be changing? We've heard about trucking and talked about that before. Labor sounds like it's tight. It's taking you guys longer to source the labor that you need versus what it was at the end of last year. Can you talk to some of those factors as well?

Well, I'm never going to say that there's no improvements available on the cost side. And we'll continue to work to be as efficient as we can. But nothing changes the fact that this business had a pricing problem, and that was driven by the downturn that we've been in for two years previous. And we just have to work the pricing back up to better levels. And I think you're seeing that in the results going from Q1 to Q2. And then going from Q2 to Q3, we're always a bit cautious as to how much our teams will be able to get in terms of pricing push. Two-thirds of our equipment is still working in the market where it's not tied to contracts or pricing agreements, so we have the availability to push. We just have to wait and see how much traction we get as we work through the year. Marc Bianchi - Cowen & Co. LLC: Okay. Thanks, Andy. I'll turn it back.

Thanks.

Our next question comes from Ken Sill with SunTrust Robinson. Your line is now open.

Yes. Good morning. Thanks for squeezing me in this morning. The integration seems to be going well. You're adding capacity. I am curious though, you're at 80% by the end of the year – above 80% in terms of marketing capacity. But if you look at the fleets that are actually working, what percentage of the available days in a quarter can they actually be online pumping if they were at maximum utilization? And where are you today? Do you have that kind of information?

Well, the majority of our spreads work 24 hours a day. And I'll tell you that the calendar has been essentially filled out since the first quarter. There just aren't a lot of open days in the calendar and that's why you see us continue to activate spreads. It's just really difficult to get more days into the existing calendars with existing spreads.

I mean, my experience is you generally need about three or four days a month for maintenance and you lose some time for moving. So, I guess what I'm getting at is, the pad drilling will allow you to get maximum utilization out of your units. But I mean, is there a limit to how many days a month you can actually have a pressure pumping trailer working?

Essentially, if you're managing the rotational equipment correctly, it can work 31 days a month. And so that's what we're moving to. As we do more and more pad drilling, we certainly have the downtime for moving between multi-well pads. But we also have places in West Texas where we set up and we can actually frac more than one multi-well pad from the same location without moving the entire frac spread. But that's why we wanted to discuss the rotational equipment. It's part of the horsepower that we have to account for. And so, the frac spread's going to be on location for long periods of times. And we're going to rotate pumps in cycle and we're going to rotate blenders and cyclones. So, we have to take all that horsepower into account in order to run the business these days because we just don't have a lot of empty days in the calendar.

I mean, so you essentially have to have some capacity that's rotating back and forth for maintenance.

Exactly.

I was trying to get a feel for how much that would be of your "working horsepower."

Yeah. We haven't called that out. But we're over...

Okay.

We're over 50,000 horsepower per spread, taking that into account.

Oh, okay. That explains that number because that seems high. Okay. And then, some of your peers have been talking about sand volumes per well. Did you guys see any shift in sand volumes per stage or per well Q1 to Q2?

We saw it move slightly up with our customers and we just haven't – we don't see anything on the horizon that shows it going down for us.

Okay. That's good. And then obviously this move to pad drilling would imply that you're going to have more DUCs just because you got to complete all the wells – I mean drill all the wells before you start completing. Is there a trend in pad sizes in the Permian right now? Are they getting bigger? Or is it kind of five wells? Is that settling on kind of an optimal size yet?

It's been a multiyear shift in the Permian, which is why we called out the year-over-year stage increase. And it's been a multiyear shift from single-well pads to multi-well pads. You're seeing a high percentage of multi-well pads in the Permian, which makes us more efficient, makes operators more efficient. And then there are cases where you do have operators that are putting on a larger number of wells per multi-well pad as well. So, that's just an evolution in the Permian. Other basins like the Marcellus, Bakken, DJ, even to some extent South Texas have started that earlier. And it just took longer to get all that going in the Permian.

Yes. And then one last question. I know that pad sizes and pad design were a big deal up in the northeast because you basically have to carve a pad out of the side of a hill. Are there any constraints on how big pads can really be in West Texas in terms of – I mean, do you have to keep the wells tightly spaced? I guess the impression in general is that it's pretty empty out there and there's lots of room.

Yes. Certainly for everybody who's been to West Texas you know there's not really a constraint at the surface. It's really more about the subsurface and how the operator wants to lay out their horizontal wells. What kind of spacing do they want or intend to have? Do they intend to do horizontals in stack plays where you have horizontals in multiple layers, and so that could increase the number of well heads? So, it's really more about the subsurface in West Texas and the strategy of the individual operator as to how many wellheads you end up with on the pad.

Okay. Thank you very much.

Our next question comes from Jud Bailey with Wells Fargo. Your line is now open.

Thank you. Good morning.

Hey, Jud.

Wanted to follow up on one of the comments earlier, Andy. You mentioned that you had – I think you said two-thirds of your fleet is not tied to pricing agreements. And I just wanted to make sure I understood. Is that suggesting that two-thirds of your fleet, are you kind of at leading edge pricing? Trying to get a sense of, for the second and third quarter how much of your – how much of your pressure pumping equipment is it, what is kind of leading edge and then how much would be left to perhaps reprice over the next couple quarters?

So, I guess that's just one way to look at it. You know with two-thirds not tied to contracts or pricing agreement, our teams are continuing to push the pricing on those particular frac spreads with those customers. And if – your ability to do that varies between customers, varies between basins. So not everything moves at once, but we do have the ability to keep pushing. And we'll just have to see how those negotiations go as we work through the year.

Okay. And I guess just to follow up on that then, for say the second quarter, is there an estimate on how much of your equipment would have been at kind of the leading edge? It sounds like it would have been far less than that two-thirds, if I understand you correctly.

It's close.

Okay. All right.

Close enough for us (55:50).

All right. And then just kind of a broad question. You guys are a bit unique with the rig business and the pressure pumping business. As you talk to customers for both sides, I'm just curious, are you observing any differences as you are talking to customers on contracting rigs the next few months versus pressure pumping? Is one a lot more active than the other? I would imagine pressure pumping is, but I'd just be curious to get your thoughts on any observations in terms of conversations with customers between the two businesses.

You know, first, there's no question I think we're not the only ones that are seeing this. The pressure pumping activity has just lagged the increase in the rig count. And that's why you're still hearing us talk about activating spreads in pressure pumping. And we still expect to be very busy in pressure pumping. At the same time, on drilling, I think there's been more concern in the market with the changes in the commodity prices that somehow rig count may drop. We just don't have that view. As an industry, I think at today's commodity price we're flat to slightly up as an industry. For Patterson-UTI, we expect it to be slightly up towards the end of the year, and that's how we see it. I think there's also a continuing highgrading in drilling to super-spec rigs, which improves things for contract (57:08) like ourselves.

And if I could follow up on that last point. If – there's a lot of different opinions on how much the rig count may or may not drop next year, but if it's down I don't know, 100 rigs to 150 rigs, but you are also in the middle of this kind of industry-wide highgrading process. How would you – if the rig count is down say a 100, how would we think about Patterson's rig count as you upgrade rigs? Do you think – is it inconceivable you could keep your rig count flat or do you think you would still soften, but maybe less than the market as you upgrade more rigs to super-spec?

It depends on the timing of when we're putting out rigs that are upgraded and creating more super-spec rigs in our fleet. But it is conceivable that total industry could drop a 100 rigs and we could still have a flat rig count depending on the timing of when those upgrades come out.

Okay. Great. I'll turn it back. Thank you.

Our next question comes from Kurt Hallead with RBC. Your line is open.

Great. Great. Good morning.

Good morning.

Good morning.

So, I had a just follow-up question on the land rig front. You guys talked about the prospects for upgrade. You talk about the dynamics in the market where pricing is not supportive of new builds. So, if you're looking at upgrades, do you already have contractual commitments in hand from customers to justify those upgrades? And then what day rate or what cash margin is required in your mind to move forward with an upgrade? And how – what's the cash margin required for a new build?

So, for the seven rigs that we've talked about that we're upgrading, which are APEX 1000s that we're moving to APEX-XK 1500s, of those seven, five are currently contracted. We expect to sign the other two in the very near term. And we're going to get day rates in the low 20s for these rigs. And so, we think for the $8 million cost of these upgrades that the payback is good and it's the right thing to do for these rigs for the market.

And then what do you – what's the cash margin needed for a new build in your mind?

It's got to be a bigger revenue than low 20s. New build rigs – and we completed one new XK and we're building an XC and they are under term contract. We need to see rates that are higher. We said on a previous call that the new XC that we're building, we've got a contract of rates in the mid-20s. That's closer to what we need for new builds. And the market's just not there yet. But the market is good for progressing the upgrades right now.

Okay. And I know you mentioned earlier in the call, in response to a question about the repricing of I think frac, but you also have the prospect of repricing some of the Seventy Seven Energy rigs as well. So, on the land rig front, how much – how far along are you in that repricing process? One-third? One-half? Any general gage of where you stand on the repricing on the land rig front?

Yes. And just to kind of explain where Seventy Seven was again, you know, Seventy Seven had a single customer at one time; they had to branch out and get customers in other basins during the middle of a downturn, which is a very challenging prospect. And so, some of their pricing might have been lower than others in order to do that. But that's what they had to do in order to get the work. There has been some opportunities to do some repricing. We've done a little bit already and we'll continue to work through the year and do more. It's hard to say the timing of some of these, but we'll continue to do work on that (1:01:01).

Okay. And then, maybe to wrap up on this one. With the incremental frac capacity that you've added here – question for either you or Mark or both of you – what do you envision Patterson being, a service company or a land driller five years from now?

Well, if you look at the projected revenues, we're looking more like a pressure pumping company than a contract driller, but we're very pleased to be in both businesses.

Great answer. All right. Thanks, gentlemen.

And our last question comes from the line of John Daniel with Simmons & Company. Your line is now open. John Daniel - Simmons & Company: Hey. Thanks. Thanks for getting me in. First one, Andy, would be, have you guys contracted any sand yet from any of the emerging West Texas sand mines? And if so, in doing that, do you expect this to have any impact on the margins?

Yeah, I would say that the West Texas sand mines are, as you put it, still emerging. And so we did intend to take some sand at some point, but we haven't gotten sand from them yet. We also haven't seen a huge push on our sand costs from Q1 to Q2 in the Permian. It's still under 10%. So that's kind of where we are on sand. John Daniel - Simmons & Company: Okay. Does it ever make sense for – just given how big you are out there, does it make sense to actually buy your own West Texas sand mine?

Well, I think we prefer to stay in the businesses that we're very familiar with as opposed to the mining business, but we have made investments in the mines in past and we've done other types of deals with mines to ensure sand supply and I think we'll continue to look at those types of prospects. John Daniel - Simmons & Company: Fair enough. And if you addressed this early on, I apologize, but have you placed any orders for new frac equipment yet? And if not, do you expect to place orders for new equipment before year-end?

We have no placed any order for new frac equipment and we do not have plans to place orders for new frac equipment. John Daniel - Simmons & Company: Okay. Thank you, guys.

Thanks.

At this time, I'm showing no further questions. I would like to turn the call back over to Mr. Mark Siegel for closing remarks.

I'd like to thank everyone for their participation in our call today. Look forward to speaking with you after our third quarter. Thanks, everybody.

Ladies and gentlemen, thank you for your participation in today's conference. This does conclude the program. You may now disconnect. Everyone have a great day.