Good morning, ladies and gentlemen, and welcome to the Patterson-UTI Energy First Quarter 2017 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will have a question-and-answer session and instructions will be given at that time. As a reminder, this conference call is being recorded. I would now like to turn the call over to your host for today's conference, Mr. Mike Drickamer, Vice President, Investor Relations. Sir, you may begin.

Thank you, Bridgette. Good morning. And on behalf of Patterson-UTI Energy, I'd like to welcome you to today's conference call to discuss the results for the three months ended March 31, 2017. Participating in today's call will be Mark Siegel, Chairman; Andy Hendricks, Chief Executive Officer; and John Vollmer, Chief Financial Officer. As a reminder, 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 first quarter of 2017. We are pleased that you're able to join us today. As is customary, I will start by briefly reviewing the financial results for the quarter ended March 31, 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 for questions. I'd like to start by saying how pleased I am with the recent completion of the merger with Seventy Seven Energy. I welcome all of the Seventy Seven employees and shareholders to Patterson-UTI. As we turn to the financial results for the first quarter, I want to remind you that because the merger just closed last week, all reported financial results for the first quarter are for Patterson-UTI on a stand-alone basis. As set forth in our earnings press release issued this morning, for the first quarter we reported a net loss of $63.5 million or $0.40 per share on revenues of $305 million. Total adjusted EBITDA during the first quarter was $63.6 million. I would like to note the financial results for the first quarter include a pre-tax gain of $11.2 million or $0.04 per share after-tax related to a real estate sale, and transaction expenses related to the merger with Seventy Seven Energy of $5.2 million pre-tax or $0.02 per share after-tax. Turning now to the merger with Seventy Seven Energy. For Patterson-UTI, the merger with Seventy Seven Energy was the most significant transaction since the merger of Patterson and UTI in 2001. Strategically, this merger strengthens our position in both U.S. onshore drilling and pressure pumping. In drilling, with the combined rig fleet of approximately…

Thanks, Mark. In contract drilling, rig demand was strong during the first quarter, driving a 22% increase in our U.S. rig count to an average of 81 rigs for the first quarter from 66 rigs in the fourth quarter. Rig demand remains robust and, as such, we expect to average 96 rigs in the U.S. for the month of April, excluding the contribution to the rig count from Seventy Seven Energy. From the Seventy Seven rig fleet, 58 rigs are currently operating and, therefore, including the contribution from these rigs post merger, we expect our rig count in U.S. to average 115 rigs in April. In Canada, our rig count averaged two rigs for the first quarter, unchanged from the fourth quarter. Both of these rigs have been engaged in pad drilling operations, which allow them to stay active after the onset of the breakup period in Canada. Accordingly, we expect to average two rigs in Canada for the month of April. The growth in our rig count in contract explorations during the first quarter reduced the proportion of our rigs under higher day-rate term contracts, causing total average rig revenue per day for the first quarter to decrease $440 to $21,200. Total average rig operating cost for the first quarter increased to $14,450 from $13,770 for the first quarter as the result of a lower proportion of rigs on standby and an increase in rig re-activation expenses. Total average rig margin per day decreased to $6,750 for the first quarter from $7,870 for the fourth quarter. At March 31, we had term contracts for drilling rigs providing for approximately $385 million of future day-rate drilling revenue. Based on contracts currently in place and including the post-merger contribution from the Seventy Seven rig fleet, we expect an average of 84…

Thanks, Andy. The completion of the Seventy Seven Energy merger further solidifies our position as the leader in both land drilling and pressure pumping in the U.S., the two primary services needed for drilling and completing unconventional oil and gas wells. Our increased scale and market capitalization, along with our strong balance sheet, position us better than ever before to succeed in an expanding energy services market. I'd like to take a minute and welcome the people from Seventy Seven Energy into the Patterson-UTI family. We have always held the highly-skilled employees at Seventy Seven Energy in high regard. They share a devotion to the same core values of safety and customer service that are cornerstones to the Patterson-UTI culture. The merger integration process has begun, and I am pleased with the integration plan that we and Seventy Seven Energy have developed. We believe this collaborative plan will help maximize the value of the combined entity. With the closing of this merger, I am excited about the opportunities ahead. We believe that many of the plans for future drilling and pressure pumping activity have already been made, and E&P companies have hedged future production. Absent an event that causes crude oil prices to fall into the low-40s, we expect pricing and activity will continue to improve. With that, I'd like to both commend and thank the hardworking men and women who make up this company. We appreciate your continuing efforts. Also I'm pleased to announce today that the company declared a quarterly cash dividend on its common stock of $0.02 per share to be paid on June 22, 2017 to holders of record as of June 8, 2017. Operator, we'd now like to open the call to questions.

Thank you, sir. Our first question comes from the line of Sean Meakim with JPMorgan. Your line is open.

Hey. Good morning.

Good morning, Sean.

Let me start with pressure pumping. Andy, I was just curious to think about – you talked about the potential to reactivate more spreads in the second half. How do we think about the levers and timing that will guide those decisions? And then just thinking about a part of that calculus, are you getting net margin improvement beyond cost recovery at this stage? And how does that factor into those decisions?

Yeah. I guess to start with, let me just talk about the margin. I think certainly part of the margin expansion you saw in our first quarter results include net pricing increases that we were able to get towards the end of the quarter, and we see the potential for this to continue as well. In terms of reactivation, we have about 30% of our total 1.5 million horsepower that's stacked right now. And we see opportunity to activate that equipment in the second half, at various points in the second half, starting with one crew early in the third quarter. Outside of that, we're going to move basically with the market demand on activity.

Got it. Okay. Thank you for that. And then just drilling side, I was just curious if you could give us a sense of the magnitude of how much of a day-rate premium you're able to get for an upgraded super-spec rig, compared to just a high-spec AC rig that's in the market, or even a relatively newer well-equipped SCR rig? Just trying to get a sense of the delta between those two in the market.

Well, in some ways, they're not exactly related because the high-spec rig market is just moving in a different pace and that's what we see in the majority of the demand. And we've seen pricing continuing to move up on high-spec/super-spec rigs through the first quarter, and as rig count continues to go up, pricing on those rigs continues to go up. We do see that over time that, because the high-spec/super-spec category pricing is moving up, that it lifts the SCR pricing at the same time.

Okay. So your expectation would be that as high-spec rigs go, SCR kind of has to go with it or else there's some kind of – at some point, that gap gets wider as a substitution effect, so you need to see movement on the SCR rigs as well. Is that the right way to think about it?

No, it's not a substitution. These are different markets. But the high-spec rig market lifts the SCR market.

Okay. Fair enough. Thank you, sir.

Thank you. And our next question comes from Marshall Adkins with Raymond James. Your line is open. J. Marshall Adkins - Raymond James & Associates, Inc.: Morning, guys. It sounds like the Seventy Seven, both rig and pressure pumping fleets, are being priced lower and it sounds like you have confidence you can get them up. So, to drill down on that issue, were they being priced lower because they're lower in quality or were they just trying to maintain a higher utilization and to do that they needed a price lower? Help me understand why you're confident you're going to get pricing and margins from that side of the business up.

First off, let's clarify. Seventy Seven Energy has a great team with great assets and they run great quality operations. But Seventy Seven had a special challenge in that they had to expand their market base from a single customer base to multiple customers, and we applaud what they've done. We think they've done a tremendous job. But that had some challenges at the same time. In the timing of us merging the two companies together, it's just the net difference in the results of the margins that you see today. But both the market and then the improvements in the market and then the combination of the merger with Patterson-UTI and Seventy Seven together improves our overall geographic footprint, it improves our overall combined customer base, and so we see good potential there. J. Marshall Adkins - Raymond James & Associates, Inc.: Okay. Some of your competitors, as they've reactivated equipment both on the rig and the pressure pumping side, have really been dinged on margins. So far, you guys seem – your margins have ramped up really nicely with activity. It seems like you're passing on more of the sand and logistics cost that maybe some others are. So help me walk through going forward, as you reactivate more of this equipment, should we worry about maybe delayed margin improvement as you reactivate them? Or do you think you can stay ahead of that? And same question on the sand and last-mile logistics pass-throughs.

So, in terms of the products, whether it's sand or chemicals, I think that our supply chain team has done a great job in managing the contracts that we have with our various suppliers across the U.S. And we have a number of different contracts in place that are layered, that expire at different points during the year. And what you saw between Q4 and Q1, the net result is very little movement in our average sand cost. And any movement that we had, we were able to pass that through. Combined with some net pricing improvements towards the end of Q1 gave us the margin expansion that we saw in pressure pumping. We do think that the market is tight on some of the finer mesh sizes, but we do also think that we're very comfortable with our contract position. And even though we might see some single-digit price increases on average going from Q1 to Q2, we have that factored into the projected margins as well. In terms of reactivation costs for pressure pumping spreads, the earlier fleets that we reactivated were costing us on average about $2 million per spread. We see this average going forward to be about $3 million to $4 million per spread, and that's really a cash cost that includes the labor. So, as you know, for 24-hour operations, it's at least 100 people that are coming on in a 60- to 90-day period before we even generate revenue. So we will see those costs in front of the revenue stream from each of those frac spreads as we continue to reactivate spreads going forward in 2017. J. Marshall Adkins - Raymond James & Associates, Inc.: Okay. All right. Great. So the margin guidance at flattish with improving activity, you mentioned it's because you're rolling in the lower-margin Seventy Seven stuff. Is part of that lower margin guidance that your reactivation costs are going to go up? Or is it just more of the Seventy Seven stuff rolling in, and then over time that gets back up to where you are?

It's a combination. I wouldn't say that it's reactivation costs going up necessarily, but more reactivation costs included in that future cost base as we reactivate spreads. J. Marshall Adkins - Raymond James & Associates, Inc.: Right. All right. Thanks, guys. I appreciate it.

Our next question comes from the line of James West with Evercore ISI. Your line is open.

Hey. How are you? This is Alex on for James.

Morning.

My first question is on the Seventy Seven drilling assets. During the merger call, you guys didn't really highlight the SCR rigs. The 58 rigs operating would seem to indicate they received pretty good traction in the interim. Have you guys been surprised about those and where do you see that segment fitting in to your broader fleet?

So we haven't been surprised on our side in terms of their utilization on their SCR fleet. You got to remember that Seventy Seven Energy has some of the newest SCR rigs that are out there in the market today and these are very competitive rigs. So, in some cases, their SCR rigs are going to have some of the same performance in some bases as some of the high-spec rigs that are out there as well, just because they're relatively new SCR rigs. So we're certainly pleased with the performance of their rig count overall. And we expect the SCR utilization to continue and improve with rig count overall, but it's also customer-specific. You've got certain customers that are out there and all they want to see is a high-spec or super-spec rig. But we do have customers that are out there using SCR rigs and very pleased with the utilization that Seventy Seven had on the SCR fleet.

Understood. And then my second question kind of similar to Marshall, I guess how much – in the second quarter pressure pumping guidance, how much of that is net pricing increases versus the dilution? And I guess my question becomes – it sounds like 2Q becomes transitory and then we see some of the benefits in 3Q. Is that fair?

I think it's fair to say that you've got a combination of several things happening. You have the combination of the merger of the two companies and the net margin result there. You've also got activation costs for further frac spreads from a labor component where you have labor on-boarding before we generate revenue. And there's just various moving parts in there. And that's kind of what's happening in the second quarter. Even though we might see some increases in the sand cost in the single-digit percentile for the finer meshes, we believe that we have that covered in the margin as well.

Understood. Thank you.

Thanks.

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

Hey, Jim. James Wicklund - Credit Suisse Securities (USA) LLC (Broker): The pressure pumping business was nothing short of amazing. The number of jobs was down to 14% and the average margin per job blew away our expectations. And I realize that may just be our problem with expectations. But can you talk about how – I mean was it – I understand prices at the end of the quarter, but this is for the whole quarter. Can you talk to me about how you did such a good job, I guess is what I'm asking?

Well, I have to give the credit to the teams in the field. I mean, our teams are really good at solid execution, running lean operations but still delivering high service quality at the same time. And because of that, we were able to push some pricing during the quarter and get some net pricing adds and continue to deliver service quality and improve operational efficiency and improve stages per day with some customers. So I have to give credit to the teams. James Wicklund - Credit Suisse Securities (USA) LLC (Broker): Well, margin per job of $58,000 versus $16,000 in Q4, that looks like a whole lot more than price. And I appreciate you all's execution. You all had the best margins longer coming into the down cycle than anybody else. That was just surprising to me, so. Okay. And going forward, you talk about how you've got your sand contracted. Do you make money on sand? And how much of your revenues in pressure pumping was the pass-through of sand?

So we do have a small margin on sand. The interesting thing is it's a smaller margin than the service. So, if we're pumping more sand in a given month or a given quarter then it becomes dilutive to the margin. James Wicklund - Credit Suisse Securities (USA) LLC (Broker): Right.

And it does vary from month-to-month and quarter-to-quarter, but we do make a small margin on sand. But I believe as activity continues to increase during 2017 following the macro on increasing rig count, then these net pricings increases that we've seen on services also move into the small margin that we get on the products as well over time. James Wicklund - Credit Suisse Securities (USA) LLC (Broker): Okay. And last, if I could, congratulations on Seventy Seven. I think that's an excellent acquisition. You've got a 15% debt to cap. Are you through?

Jim, we're never through. We're always looking for good opportunities, Jim, so. James Wicklund - Credit Suisse Securities (USA) LLC (Broker): Okay. But it took you a long time to do this one. So do we have to wait this long to do the next one?

Jim, my crystal ball is a little fuzzy on how long it takes for the next deal. James Wicklund - Credit Suisse Securities (USA) LLC (Broker): Okay. I mean, you don't want the market to run away from you before you have the chance though, right?

Well, I think the interesting thing in this market is I don't think you have to rush and I think the market can still have opportunities over the next couple of years. James Wicklund - Credit Suisse Securities (USA) LLC (Broker): Okay, guys. Thanks so much.

Thanks.

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

Hey. Actually that was pretty good. That last name, pretty good. So I guess let's talk about your guidance. Trying to put the pieces together. Can you just confirm that your guidance implies about $100 million of EBITDA in 2Q?

Don't have that in front of me for the overall combined EBITDA of all the different companies.

Okay. All right. I'll just follow up after the call just to make sure we have all the moving pieces right. I guess I also wanted to chat about the contracts for SSE on the pumping side and on the land rig side with Chesapeake. So could you talk to that? When those roll off on the rig side and the pumping side?

I think the best way to describe it is with the combined businesses with Patterson-UTI plus Seventy Seven Energy on the drilling side, we don't have any situation with contracts that produces any headwind other than ongoing long-term contracts. What's happening in the margins in the drilling business, and I'm talking about the combined new business, is for rigs that are moving out we see improving margins. We have some contracts that we've had for a while. As those roll off, those are going to roll closer to a spot at the lower margins. So we have several moving pieces there. And then combining the two entities together, you get the net result of the margin projection that we gave you for the second quarter. In pressure pumping, in terms of contracts what we see is it's really about two-thirds of our active fleets have the ability to move the pricing with the market.

Okay. All right. And so we can have the right run rate as we get into 3Q, could you just help us with what the underlying rig count assumption is for SSE in 2Q because we don't have a full quarter there, and then the same for the revenue side on pressure pumping?

It really gets back to the averages that we gave you. We expect that the rig count is going to continue to increase during the second quarter. And including both Seventy Seven's fleets and Patterson-UTI's fleet, we expect the rig count in the U.S. will average 143 in the second quarter.

Okay. So what does that assume that – so if we think of legacy PTEN, how much is that assumed to be up in 2Q? That'll help us. 20%

Yeah. We're moving on to combined company numbers now.

Well, I know, but the thing is – so let me ask you, so 143 rigs, is that a pro forma for 90 days for SSE? Or is that a pro forma for 70 days?

That's a function as of the close on April 20.

Right.

(38:14)

I can follow up afterwards, but basically I'm trying to understand – I want to understand what SSE is, the run rate, going into 3Q. We just don't have a full quarter. I'll follow up after the call. Thank you.

Thanks.

Our next question is from Brad Handler with Jefferies. Your line is open.

Thanks, guys. Good morning and thanks for taking my call. If my question is redundant, I apologize. I had to hop off for just a couple of minutes. But can we talk first about drilling operating expenses? So, obviously, you've given us the margin guidance on the second quarter, so it's $13,900 a day. That I get. Obviously, there was also some volatility, some fluctuation as standby rigs came off and then you also have a little bit of sort of the reactivation cost of bringing rigs back into service I guess. How can we think about that maybe in 3Q? Where should we think about operating expenses a little bit longer-term just settling out for you, please?

Without going into the details of 3Q, I think it's safe to say that we're getting closer to the bottom in margins. But we still, as I mentioned earlier and it's no problem to repeat, as I mentioned earlier, we have some moving pieces here because we have a mix of contracts that we've had for a while now that are rolling off and moving closer to spot. We have rigs going out that are increasing in margin as they go out. And then we have the combination of the merger. We also have rig reactivations where we have labor costs in front of the revenue of the rig. So there's moving pieces in there, but we're getting close to the bottom in the margins.

Okay. That's certainly good to hear. And I guess I was just trying to parse it on operating expenses, per se. And so, if I remove the rig reactivation element of that, maybe it's a combined – so it's a combined fleet question of course, but where do you think daily OpEx sort of settles out?

We think it's similar on a per day basis. We don't really pull the rig reactivation costs out of that. So per day would be similar.

So it will wind up staying similar to where you're talking about for Q2?

Correct.

Is that what you mean to suggest? Okay. Got it.

Yes.

Okay. And then I guess maybe just a quick follow-up for me just on that last answer to one of Chase's questions. So, in other words, do you have contract commitments and therefore fixed pricing on roughly a third of the pro forma pressure pumping fleet? Is that the – just want to make sure I'm interpreting what you said correctly.

Yeah. And let me say it this way. So, two-thirds of our active fleet has the ability to move with pricing and the one-third that's under either some kind of contract or pricing agreement doesn't extend very long through the year. I would say that the majority of that rolls off before the end of 2017, if that helps.

It does. It does. Okay. Thanks, guys. I'll turn it back.

Thanks.

Our next question is from the line of (41:34).Your line is open. Our next question is going to be from Michael Lamotte with Guggenheim. Your line is open.

Hey. Good morning, guys. Andy, I know there's a lot of moving pieces and I want to sort of get back to the structural cost differences between Patterson and Seventy Seven. And maybe if we look at first quarter as the baseline and you look at the difference in margin in the two businesses, how much of that difference would you say is contract and pricing-related versus cost structure? I mean, is it a 30%-70% split, 50%-50%?

I think there's a mix of both, without getting into the details. Patterson-UTI is a larger enterprise than Seventy Seven was in the first quarter. So we had a little bit more efficiency in the supporting costs side. There's also an element of pricing on the Seventy Seven side as they expanded their customer base and did a great job doing that. But it's really about the go-forward and we feel like we're in a good position for the combined entities moving forward through the year.

Well, that's actually what I was trying to get at is sort of thinking about the speed with which sort of normalized margins – you could begin to normalize those Seventy Seven margins to the Patterson level and what the frictional elements are to that? I mean, you mentioned on the answer to Marshall's question that moving from single to multiple customers is sort of frictional. But is there anything other than that dynamic that slows this margin progression down or uplift slows it down?

Michael, I just would observe that we closed the merger exactly one week ago. And at this point, we're still getting our arms around all the details of their operations. And so, giving an exact prediction as to when their margins increase and get to the same level as the Patterson margins, pretty difficult for us to give a good fix on that at this moment a week later.

Fair enough.

But I will reiterate...

I'll follow up with you next week.

Thanks for that.

I will reiterate that second quarter margins are nearing the bottom for us.

Okay. And then, Andy, on the 90% utilization for super-specs, as we start reactivating rigs sort of further in the stack, are they geographically in the right markets? Are we, within a quarter or two, going to start to see rigs needing to move?

I think in some cases we'll have some rigs moved. I think that when we do move rigs, we get support in the contract from customers to help offset the costs to move those rigs. And in our particular case, we have the opportunity to continue to do some upgrades. I went through the list of items in the total CapEx. One of the pieces that's interesting there, if you go back to what we said on the last call, in terms of rig upgrades and new builds at the last call, we said we had earmarked $115 million in the CapEx budget. Now we're at $145 million in the CapEx budget. And we're certainly happy with the pricing levels we're getting on the projections for what the payback is on those upgrades.

Yeah. It's still looking at less than a year, payback?

I wouldn't say it's less than a year but it's in that two- to three-year range...

Okay.

...on that upgrade component.

And then last one for me. In light of the OneStim joint venture, now having two competitors with roughly 3 million horsepower in capacity, does it change the thinking on scale in the frac business? It wasn't that long ago that we thought 1 million horsepower was sufficient scale and now you guys are at 1.5 million horsepower and scale just seems to be moving. How do you think about it?

In general, I think that scale still matters in this business, especially because of everything that happens before you even get to the well side. But I think it's important – when you look at Patterson-UTI and now the combined merger of Patterson-UTI and Seventy Seven Energy and our footprint, we're a 1.5 million horsepower. So we're not as big as the two that you mentioned, but we're not in all the basins that they're in either. So our focus is with the primary aspect of our horsepower, 850,000 horsepower is in Texas. And we're also in the Mid-Continent and we're also in Appalachia. So, if you look at our concentration in the regions that we're working, we think we're in great shape.

Great. Thanks, guys.

Thanks.

Our next question is from the line of Ken Sill with SunTrust Robinson Humphrey. Your line is open.

Thank you. Surprised to get in here. So one of the questions, you were talking about the costs for reactivating a frac fleet, and saying that you're hiring an average of 100 people per crew. I'm assuming that's for 24-hour operations. That just seemed a little bit high to me. How many people do you guys run in an average crew?

The average pressure pumping crew that's working 24-hour operations for us has 100 to 110 people on it. We generate over 90% of our revenues, of our total active fleet, from 24-hour operations. So, when we do these reactivations, we're going to have labor costs as we bring on people before we start generating revenue from a particular frac spread. And that labor cost can start 90 days before we generate revenue. And that labor cost grows over that 90-day period before we generate that revenue.

I was just surprised by the head count. So, that kind of leads to a second question, which is, are you guys seeing an evolution in the size of the average frac spread you're putting out? What's the average spread, particularly in Texas, in terms of hydraulic horsepower today versus what would it have been a couple years ago?

Yeah. We've seen somewhat growth in the amount of horsepower that we put out. Some of it has to do with just changes in the operating pressures in where we're fracking these days versus where we may have fracked historically. So we previously might have lifted a frac spread at a 40,000 to 45,000 horsepower and today, depending on where it is in the U.S., it might be 45,000 to 50,000 horsepower.

And final question, just trying to figure out what capacity could be out there, I mean what you can do with the fleet. Given you got longer laterals and higher sand loadings, you're solving that issue with more horsepower. Does it take more time to pump a bigger sand load? Or is that just a function of – I mean, there's a lot of moving pieces, but just on average does it take more time to pump a bigger sand loading per stage?

Certainly when you compare a horizontal well today versus what we were drilling two years ago on average in Texas, with longer laterals and higher volumes, we are pumping more time. But what that means for the industry in general, if you look at the total number of wells that have to be completed during the year, it takes more time to pump on that aggregate number of wells, which means more frac crews operating than historically in the past for the same number of wells.

Yeah. Well, actually and that leads to another question and then I'll stop. With the rigs getting more efficient, is the ratio of rigs needed or running to keep a frac crew busy? Is that changing?

That's gone down a little bit. So it's moved down a small percentage but, yes, with the efficiency improvements in operating times for the rigs. And again, on aggregate over the last few years, that certainly has changed a little bit. But I think it's also important to note when you get into a discussion on rig efficiency, rig efficiency now is looking relatively flat over the last year after having improved over the last two years. And a lot of that is not just – we get into a lot of complications talking about what it means in terms of rig efficiency and what drives that, but the thing you have to remember is our rigs are still as efficient as they were yesterday but you have so many more operators working now than you did in 2016, and not all of the operators are as efficient. Some of the smaller operators that are now working in some of the states that have shorter programs are just not as efficient as some of the bigger program drillers. So it changes that drilling efficiency equation when you look across aggregated numbers across the U.S.

That makes sense. All right. Thank you, guys.

Thanks.

Our next question comes from the line of Marc Bianchi with Cowen & Company. Your line is open. Marc Bianchi - Cowen & Co. LLC: Thank you. Just on the pressure pumping guidance, I wanted to confirm that that includes the addition of one crew from here in the third quarter that was mentioned in the press release. Is that correct?

That's correct. Yeah, we're taking into account the labor that we're bringing on to crew up that frac spread that starts in early third quarter. Marc Bianchi - Cowen & Co. LLC: Okay. Thanks. Sorry my phone cut out there for the last part of your comment, Andy, but I think I got it. And as it relates to additional crews that could be added in the second quarter, is it such that the lead time is just so long that, really, you couldn't get any additional crews to work in the second quarter to meaningfully increase the revenue. It's more of a third quarter benefit at this point?

I think it's the way we look at the market. And I've heard various pronouncements by other companies. But the way we look at it is we're still very focused on margin. We want to get good returns for our frac crews. We're also very focused on ensuring that we continue to deliver high service quality as we increase the number of frac spreads that are working. So our approach may be a little bit more measured, but we're going to protect the margins and do our best to continue to deliver high margins in this business. Marc Bianchi - Cowen & Co. LLC: All right. Okay. And on the rig side, you mentioned 198 APEX-class rigs now with the combined company. How many of those, or maybe it's all of those, would you consider to be upgradable to super-spec?

I would consider all of them upgradable to super-spec. We mentioned that we have 100 super-spec rigs today. And I also mentioned that we've actually increased our CapEx projection for what we'll be spending on rig upgrades and new builds. Where we said it's going to be $115 million at the last call, we raised that to $145 million for this call. Marc Bianchi - Cowen & Co. LLC: Got it. Okay. Thanks. And then last one. Mark, I appreciate the comment on having just closed the merger, but it does seem to – the guidance for G&A seems to just be the combined G&A for the two companies. One, is that true? And two, kind of how quickly do you think we'll start to see the benefit of the synergies that you talked about?

Yeah. This is John Vollmer. Yes, for the quarter, it reflects their full G&A plus about $3 million for the 71-day period. And we assume we get additional savings in the third and fourth quarter. And I believe Andy's intention is that we will have the synergies accomplished by the end of the year, as previously indicated. Marc Bianchi - Cowen & Co. LLC: Okay. And that number is still $50 million?

We believe that's still a good number. That's a number that we gave when we announced the merger. And you got to remember, at the same time, activity continues to increase and the head count for the combined companies is going to be greater at the end of the year than it is today.

And one other point on the synergies and the cost savings opportunities: those aren't all G&A. A portion of that relates to operating costs and drilling and pressure pumping, given our increased scale, buying power, et cetera. Marc Bianchi - Cowen & Co. LLC: Okay. Great. Thanks for that. And I'll turn it back.

Thank you. And our last question comes from John Daniel with Simmons & Company. Your line is open. John Daniel - Simmons & Company International: Hey, guys. Thanks for putting me in. Just a sort of a big-picture question here. Now that we are sufficiently deep into earnings season, it feels as if everyone, including you guys, are managing their businesses assuming we migrate from, call it, $50 world to $60 oil. Given that we're now back again sub-50%, and who knows what OPEC's going to do, at what point do you think Patterson may be starts to manage for a $50 world and what would that entail?

Well, John, it's an interesting question but I don't think we've ever really said that we're managing for $60 oil. The way we look at it is, over the last period of time since summer of 2016 with oil trading in the $50 to $55 range, rig count goes up. John Daniel - Simmons & Company International: Yeah.

And when we've seen these pull-backs into $47, $48 range, we haven't seen customers who'd make plans to change those plans. And so, while there may be some customers that take a pause at $47, $48, it appears to us that if customers/operators already have these plans in place they continue on with these plans. John Daniel - Simmons & Company International: Okay. Fair enough. Just one final one. And I know it's early into the Seventy Seven deal, but I'm curious if you can say whether or not the Great Plains business will be core to you guys or if this is something that you might part ways with? And the reason I ask is I recall you guys having sold other non-core product lines following other deals and I'm thinking specifically about Wireline after you bought the Key deal.

I'll answer the question by saying at this point we like the business, we like the opportunities that we think we see in the business and so we have no current intention whatsoever to part with the business at this point. I think there's opportunities to expand it.

Yeah. We see potential to expand this business with the Patterson-UTI footprint. John Daniel - Simmons & Company International: Yeah.

Great Plains Oilfield Rentals has a footprint based on the company that it was a part of and the single customer it was servicing historically. They've done a great job at expanding their customer base. And now we offer more facilities and a larger geographic footprint for them to expand into well, along with a great balance sheet behind them.

John, one additional thought. We basically like rental businesses is the first point. John Daniel - Simmons & Company International: Yeah.

And the second point is, fundamentally, is that the first exposure I ever had to the oil patch was in the oilfield rental tool business. So, quite honestly, I'm feeling very comfortable about this one. John Daniel - Simmons & Company International: Fair enough. Just thought I'd ask. Thanks, guys.

Thanks.

I'm not showing any further questions. I'll now turn the call back over to Mr. Siegel for closing remarks.

I'd like to thank all the people who participated in our call and thank you for being interested in our company. We'll join you again at the end of next quarter.

Thanks.

Ladies and gentlemen, this does conclude the program and you may now disconnect. Everyone, have a great day.