Good morning. My name is Emily and I will be your conference operator today. At this time, I would like to welcome everyone to the Patterson-UTI Energy, Incorporated Third Quarter 2018 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks there will be a question-and-answer session . Thank you. Mike Drickamer, Vice President, Investor Relations, you may begin your conference.

Thank you, Emily. Good morning. And on behalf of Patterson-UTI Energy, I'd like to welcome you to today's call to discuss the results of the three and nine months ended September 30, 2018. Participating in today's call will be Mark Siegel, Chairman; Andy Hendricks, Chief Executive Officer; and Andy Smith, 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 or 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 for what the company expects. The company undertakes no obligation to publicly update or revise any forward-looking statement. The company's SEC filing 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 2018. We are pleased that you can join us today. This morning, I will turn the call over to Andy Smith who will review the financial results for the quarter ended September 30. He will then turn 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. Andy?

Thank you, Mark, and good morning. As set forth in our earnings release issued this morning, for the third quarter we reported a net loss of $75 million or $0.34 per share on revenues of $867 million. Included in our net loss is $65.9 million of non-cash pre-tax impairment charges. Excluding these charges our net loss from the third quarter would have been $21.1 million or $0.10 per share. These impairment charges include $48.4 million related to the retirement of 42 legacy non-APEX drilling rigs and related equipment and $17.4 million for pressure pumping equipment. As customer preference across the industry continued to shift to super-spec drilling rigs, these 42 rigs have limited and diminishing commercial opportunity. In pressure pumping, the impairment was primarily related to obsolete sand handling equipment that has been replaced with more efficient solutions. Consolidated adjusted EBITDA for the third quarter was $202 million. During the quarter, we repurchased an additional 2.9 million shares of our common stock at a total price of $50 million. This brings our total repurchases for the year to $100 million or 5.5 million shares or 2.5% of the company's outstanding shares at the beginning of 2018. In addition to the buybacks, we paid our regular quarterly dividend of $0.04 per share, which resulted in an additional $8.7 million return to shareholders during the quarter. We will continue to evaluate buybacks given our expected level of free cash flow and competing capital needs. At September 30, 2018, we had approximately $200 million remaining under our share repurchase authorization. During the quarter, we continued our practice of prudent use of financial leverage and ended the quarter with net debt-to-capital of 19.5%. Projected capital expenditures for 2018 remained unchanged at approximately $675 million. However, as we discussed last quarter, we redirected some of our planned capital spending from pressure pumping to drilling, reflecting the near term opportunity set for both businesses. For the fourth quarter, depreciation expense is expected to be approximately $212 million, SG&A is expected to be $34 million, and our effective tax rate is expected to be approximately 17%. With that, I'll now turn the call over to Andy Hendricks.

Thanks, Andy. In the contract drilling, our rig count during the third quarter averaged 178 rigs compared to 176 in the second quarter. The two rigs' sequential increase was less than we expected as opportunities to increase our Canadian rig count did not materialize. Our U.S. rig count during the third quarter matched our expectations and the U.S. market for super-spec rigs remains strong. With strong demand for super-spec rigs, average rig revenue per day for the third quarter was higher than we expected with a $410 sequential increase to $22,280. Average rig operating costs per day was in line with our expectation at $13,810. Accordingly, average rig margin per day increased during the third quarter by $200 to $8,470. At September 30, we had term contracts for drilling rigs providing for approximately $825 million of future dayrate drilling revenue. This is a sequential increase of more than 20% in one quarter compared to our backlog at June 30 of approximately $680 million. Based on contracts currently in place, we expect an average of 127 rigs operating under term contracts during the fourth quarter and an average of 81 rigs operating under term contracts during the 12 months ending September 30, 2019. Since the beginning of this year, we have completed 12 major rig upgrades including one thus far in the fourth quarter. We have a customer contracts to deliver two additional rigs with major upgrades later in the fourth quarter and two in early 2019. I'd like to note that while we use the term major upgrades, these rigs are essentially being built to like new condition. The rigs receiving the major upgrades are primarily lower capacity rigs that were built for drilling shallower wells such as in the Barnett Shale. These rigs are undersized in the current market…

Thanks, Andy. Fundamentals remain strong for U.S. onshore drilling and completion activity. Continued growth in super-spec drilling activity has been driving growth in the number of DUCs. The expected fourth quarter slowdown in completion activity combined with increasing drilling activity should cause the growth rate in the DUC count to accelerate. This increase in the DUC count bodes well for an increase in future pressure pumping demand. We expect this demand will begin to materialize early in 2019 as E&P capital budgets reset based on higher current commodity prices than in the prior year. This expected increase in pressure pumping demand in 2019 is also supported by a favorable macro backdrop for the energy sector. Global economic growth continues to drive increasing demand for oil while supply growth is being negatively impacted by geopolitical issues and several years of under-investment in new large-scale oil and gas projects. Additionally, the amount of spare oil production capacity available to offset supply disruptions is both dwindling and unproven. The favorable macro environment is already apparent in contract drilling which accounts for approximately two-thirds of our EBITDA. We see great value in our position as a leading provider of super-spec rigs. Let me reiterate Andy's comments that super-spec rigs are largely sold out requiring operators to get in the queue and wait for an upgrade if they'd like to add an incremental super-spec rig. This queue and the resulting conversations about longer-term drilling plans is allowing us strong visibility in the future super-spec rig demand. Additionally, customer appetite for term contracts in a rising dayrate environment confirms super-spec drilling activity should remain strong. I am pleased to announce today that the company declared a quarterly cash dividend on its common stock of $0.04 per share to be paid on December 20, 2018 to holders of record as of December 6, 2018. With that, I would like to both commend and thank the hard-working men and women who make up this company. We appreciate your continuing efforts. Operator, Emily, we would now like to open the call to questions.

Certainly. And your first question comes from the line with Marshall Adkins with Raymond James. Your line is open, please go ahead. J. Marshall Adkins - Raymond James & Associates, Inc.: Good morning, guys. Your frac business this quarter has meaningfully outperformed most all the peers that have reported. Two questions I have on that. Number one, could you give us more color on how you're able to achieve that? I know you brought the count down a little bit which probably helped margins but just give us a broader picture of how you have remained more competitive than average, number one. And then number two, you gave us great guidance on Q4, thank you for that. I am also curious as to some speculation on how you see the market unfolding next year. Is it a second half of 2019 recovery for pressure pumping or do you think it happens sooner? So, those are my two questions.

Hey. Good morning, Marshall. So, thanks for the question. In terms of pressure pumping and what we are seeing in the market, if you go back to our second quarter earnings call, we were saying that we are already seeing that the market was oversupplied. The third quarter had uncertainty with a fair amount of white space in the calendar. It was kind of a challenge to really understand how much white space we were going to see. And as we work through the quarter, our teams did a great job trying to respond to what was happening in the third quarter and make sure that we are right-sized as things materialize. Our teams also did a great job filling some of that white space in the calendar in the third quarter as well, which allowed us to do little more revenue than we thought we were going to do, the projections that we gave you on that July call for the second quarter. So, that's really what it was. It was a lot of basic blocking and tackling in the pressure pumping business just to try to make sure that we were right-sized as we worked through that quarter. And so, we brought the number of spreads down from 25 at the beginning of the quarter down to 21 spreads at the end of the third quarter. J. Marshall Adkins - Raymond James & Associates, Inc.: Were those – just a quick follow-up there, were those spot or dedicated fleets where you actually able to fill the white space? I assume it's spot market but just out of curiosity.

Yes, filling white space right now is basically just picking up spot work and inserting it where you may have delays or breaks in your current schedule and those delays or breaks could be on spot or on dedicated agreements. The majority of our spread do work on dedicated agreements, but we do see customers slowing down and pulling back on spending right now especially in the fourth quarter. J. Marshall Adkins - Raymond James & Associates, Inc.: Okay. Sorry, go ahead, Mark.

Marshall, I just – yes, no problem. I just thought I would jump in a little bit. We have seen, as you well know, an increase in the DUC count of approximately 25% from January through the end of the third quarter and that DUC count is probably going to increase during the fourth quarter as E&Ps delay completions for various reasons. We feel that they're going to want to complete those wells early in 2019. And so, exactly timing the particular day, month, year they do that is hard but we think it's definitely a first half 2019 kind of prospect. J. Marshall Adkins - Raymond James & Associates, Inc.: Perfect. That's helpful, guys, and I'll turn it back over, thank you, all.

Thanks.

Your next question comes from the line of Sean Meakim with JPMorgan. Your line is open, please go ahead

Thank you. Hey, good morning.

Morning.

Morning.

So, I think investors are going to applaud that decision to stack equipment rather than fight for work into year-end. But so as we look forward to 2019 what would be your best guess – maybe a similar question asked a different way, how long do you think it takes for activity – for pumping activity get back to 2Q, 3Q type of levels? And when it does is it fair to say that given some of the operational challenges you all had earlier in the year that you would expect to be able to get your profitability higher in that type of environment compared to what we delivered, say, in 2Q 2018.

So, the timing of some of how this is going to materialize is still yet to unfold in 2019, but we are very upbeat on 2019 in terms of the completion activity just based on what we're seeing in drilling activity. Our drilling business gives us a lot of foresight and marketing knowledge on what's happening in the industry. So, we really feel like there is going to be an acceleration in the inventory of the drilled but uncompleted wells in the fourth quarter and going into the start of 2019. We do have some customers that say that they are going to be starting in early 2019 on the completion side right after the year starts and the budgets reset. So, we're already getting some of that discussion with some of the customers. Now, how much and how fast I think it's difficult to predict. There are several things happening in 2019, you have the budgets resetting at a higher commodity price as we discussed. You also have some of the takeaway capacity and the Permian continuing to improve. And the budget issues are not limited to the Permian, that is across the U.S. onshore. But of course as the takeaway capacity improves as well you're going to get an uplift in completion as operators prepare for that increased takeaway in advance.

And then any other comments on how you expect your profitability to shape up in that type of environment whenever it does materialize relative to what you did this year?

Yes, as I said, we have been very focused all through 2018 on trying to improve our profitability in pressure pumping and we're going to remain focused on that. We don't think it's about market share. We do think it's about trying to maintain the profitability per spread and pressure pumping.

Thank you for that and then just thinking about capital allocation for next year, can you maybe just walk us through how you think about prioritization of cash uses? Directionally, do you think CapEx will be higher or lower? You got of course the upgrade potential that you see continuing to unfold, but then perhaps reactivation in some of the other – some of the other CapEx spend on the pumping so you end up being less than what you experienced in 2018. Just maybe kind of where you see things based on what you know today.

I guess the response that I would like to give is that we set our capital budgets in late December, set our operating and capital budgets in late December and we feel that by doing so at that time we have the sort of maximum visibility into 2019 that a company could have. We typically have followed a rule of announcing our plans for capital expenditures on our call in February as we announce fourth quarter results. So, I expect that we are going to continue to follow that same approach this year. With that said, I think that we are very focused on returns and that return focus is really causing us to think seriously about every dollar we spend as we always have. And I'd also point out the fact that we have returned substantial amounts of capital to the investors already through three quarters of this year in the forms of substantial amount of buyback as well as dividends. And quite frankly, that buyback and dividends and that return of capital seems to me to have gone relatively unnoticed by our shareholders and the analyst community and I just want to call that out as being a very important part of the story I think for this year.

Fair enough. Thank you, guys.

Your next question comes from the line of James Wicklund with Credit Suisse. Your line is open, please go ahead. James Wicklund - Credit Suisse Securities (USA) LLC: Good morning, guys. Mark, on the statement, on the comment of returning cash to shareholders, you guys obviously aren't any better at timing the market than we are, so I sure can't criticize. But if you look at where you bought stock this year, it was higher. Have you guys considered just having a constant buyback instead of an episodic buyback or do you just buy back when it's cheap and you keep buying it back as it gets cheaper? What is the methodology that you guys have for deciding to buy stock?

Well, I guess I would quarrel, Jim, with your concept that we are doing it episodically and that we are doing it at the top. What we have done historically is buy stock during each of the three quarters so far during this year and we have done so kind of in a relative – regular program that has been very even across the days, months, a period of time where the market is open for the company. So, quite honestly I think it has been pretty strategic in a market such as the one we are facing in which the stock price has trended lower the whole year. It figures that the stock you bought in the early part of the year is more expensive than the stock you bought in the later half of the year. The reverse would have been true if we were in an uptick, a rising market. And so, it's one of those things where I don't see that anybody who's involved in a buyback program can always time the market. James Wicklund - Credit Suisse Securities (USA) LLC: No, no, and I am not arguing – like I say companies don't do it any better than us. And it's not that it's been episodic, I am just saying there are several different options. One is regular as stated, one is episodic, and one is just you decide to buy it back and it seems to be the latter. You bought back stock three quarters in a row. I am just wondering what methodology you guys use then to decide this quarter the stock price is X and our bell ring is on Y, what's Y? What do you look at to decide whether to buy your stock tomorrow?

Jim, I guess I wish it was just a two-factor decision but it is a multiple factor decision. We are thinking about what is our free cash generation. We are thinking about what is our expected capital expenditures. We are thinking about possible M&A opportunities. We are thinking about all kinds of other variables, amount cash available to us, lines of credit, situations of that sort, all kinds of variables as well as stock price. And so, at each given point, our board and management conclude what they think or what we collectively think is the right approach for the next quarter and then execute it.

Jim, I'll add that when it comes to running the business, we're really focused on trying to maintain capital discipline, especially around capital expenditures, whether it's maintenance and trying to be smart about how we spend on maintenance or on the growth side where we're trying to de-risk dollars that we're investing into growth CapEx and minimizing that. And the history of the company is returning cash to shareholders as you well know. And so, it's part of my job to make sure that we minimize any capital expenditures and help generate free cash flow and so we can return cash to shareholders and then we have to find the best mechanism to do that after that. James Wicklund - Credit Suisse Securities (USA) LLC: And you've done a great job of allocating capital to your different parts of the business and focusing on returns. It just sounded more like it was availability of capital and where the stock price was as opposed to some metric of return based on stock price. That was really my only point. My follow-up, if I could – I'm sorry, go ahead.

I was going to say it's certainly a function of what we believe our free cash flow is after CapEx during a given quarter as well. James Wicklund - Credit Suisse Securities (USA) LLC: Okay. My follow-up, if I could, is really on directional drilling. When you guys first bought this, the guidance was we can get this thing to 30% margins and I know that you reallocated some costs this quarter and that put you at 13%. But just back of the envelope it was adjusted – if you wouldn't have done that I guess it was closer to 16%. It kind of isn't living up to your expectations. You note that you need pricing. Has that been – are you behind plan on where you expected to be in your directional drilling business right now?

I think it's safe to say that yes we are behind plan. It hasn't been generating the margins that we've been aiming for in 2018 and we're still working with the management teams to make every effort to improve that. There's efforts underway to improve the operating cost to run some of this equipment in the harsher environment that we are doing with the super-spec rigs. We're also going to make every effort to push pricing as the rig count continues to improve as well. James Wicklund - Credit Suisse Securities (USA) LLC: Can you get to 20% margins without price?

I think we're certainly focused on improving the margins. Where that goes from here based on the challenges in 2018 is a little bit more difficult to call out today but we're working on it. James Wicklund - Credit Suisse Securities (USA) LLC: Understand. Okay, thanks guys. Appreciate it.

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

Hey. Good morning, guys.

Morning.

I wanted to focus on the main driver here of earnings and particularly, over the next couple of quarters, the rig business. So, you've got – I think Andy, you said 53 now APEX rigs that can be upgraded to super-spec down from I think 56 or so recently. I know you guys are going to be very careful on capital and what you put into the market and so you're going to want to have contracts. But as you have these discussions with customers, are you starting to order long-lead-time items, developing an inventory so that when they do hit go on contracts you can get out there quickly?

Yes, James, thanks, and as you know, as we look at these major upgrades and with the investments it takes to do this, we want to de-risk these dollars with a long-term contract to be able to do this at good dayrates that gives us the economics. But of course we have to keep some long-lead items in the order process and that's within the current CapEx budget that we gave you. So, we are ordering some of the longer-lead items for delivery into 2019. If we don't end up using those to upgrade rigs, we'll hold them as spares. These are not large dollars compared to the overall budget, but we do want to stay slightly ahead on long-lead items but we wouldn't build a rig on spec or upgrade a rig on spec.

Okay. And then should we expect, based on the conversations you're having plus the outlook for the industry overall, should we expect the same type of cadence of upgrading rigs as we've seen the last year or two? I mean just I guess it's been 10, 15 per year or so.

Well, we mentioned that we have two to deliver early in 2019 and as we discussed we're getting some long-lead items already on order. But I think it's too early to tell exactly what the cadence is going to look like in 2019. I think the good news is that we're in discussions with customers for 2019 beyond the two major upgrades that we plan to deliver early in the year. But as to what that cadence is going to look like, I think it's still a bit early.

Okay, got it, all right. Thanks Andy.

Your next question comes from the line of Marc Bianchi with Cowen. Your line is open, please go ahead. Marc Bianchi - Cowen & Co. LLC: Thank you. Following on the upgrade conversation, you've got these four more rigs that are going into the market here in fourth and first. What kind of contract term do these rigs have and what do the payback periods look like for the upgrade investment you've done?

Yes, so for the four major upgrades that we announced on the Q2 earning call, we said that we signed contracts for four years for each of those rigs and that the payback period based on those dayrates and margins is within that four-year period of those contracts. Marc Bianchi - Cowen & Co. LLC: And Andy when you...

Those are the two rigs that are being delivered at the end of this year and two rigs delivered in early 2019. Marc Bianchi - Cowen & Co. LLC: All right. Okay. And when you calculate that payback, that's on the – is that on the total margin or is that on the additional margin that you're getting because of the upgrade investment you're making?

I guess we don't separate the two. We look at it in terms of the dayrate that we're getting on the rig for that upgrade and what that payback is based on the cash spent. Marc Bianchi - Cowen & Co. LLC: Okay. And then as you look at opportunities beyond these four, would you say that they would be similar with that four-year term in payback or are you seeing things evolve differently?

I think it's too early to say how things are going to evolve past those contracts. But I think suffice it to say that we do need long-term contracts at good dayrates in order to do more of these upgrades and finish some more of these rigs. Marc Bianchi - Cowen & Co. LLC: Got it. Okay. Maybe if I could just ask one more on the pumping side. The fleets now you've got 21 in the field and four that you put on the sidelines. Given what you see here over the next quarter or two, would you say – is it fair to say that unlikely you would be stacking additional fleets? And kind of curious what the utilization opportunity is on the 21 that you have in the field right now, maybe how much white space there is to be absorbed as activity comes back up?

So, we plan to operate 21 spreads during the fourth quarter based on the projections that we have. There is some white space in that calendar just because of the seasonality that's built into some of that workload. That's not likely to change in the fourth quarter but it could have some variability, so it is a bit challenging to predict. That continues on likely into the first quarter but at the same time you get some budget resets from the customers and we are already in discussions with some customers who want to restart early in the fourth quarter. So, we certainly intend to hold on to experienced personnel and we're going to make every effort to be ready to respond. Again, our focus is going to be on margin per spread and so we want to make sure that we are maximizing that as we activate in an upturn in 2019. Marc Bianchi - Cowen & Co. LLC: Okay. Well, thanks for that. I'll turn it back.

Your next question comes from the line of Jud Bailey with Wells Fargo. Your line is open. Please go ahead.

Thanks. Good morning. A follow-up there on pressure pumping, if I could. If I look at the revenue guidance and the gross profit guidance kind of back into a decremental that's probably in the mid-twenties I think I'm doing the math right. And if I'm correct, what are the drivers to keep decrementals at such a reasonable level given the magnitude of the revenue drop? Is it visibility on pricing or something you're doing on the cost side? I know you said you are rationalizing cost as best you can but I would assume you're trying to keep staffed up like you said as well to be ready when things recover. So, could you help us kind of think through the kind of what you're suggesting from a decremental margin standpoint for the fourth quarter?

As we work our way down to the third quarter from 25 to 21, we're trying to ensure that we are keeping the cost in line when we do that. So, going into the fourth quarter, again we're having a lot of emphasis on cost and spending and keeping that tight in the fourth quarter. We've got some white space in the fourth quarter as well and there is going to be a shift in the mix of the customers with the shrinking from 25 to 21, so there's various moving parts that are in there.

Okay. And is there – in that guidance is there a contemplated, any weakness and or rollover into lower pricing or are you pretty much set from a pricing standpoint this quarter from what you can tell today?

For the most part our spreads are working as dedicated crews under dedicated agreements and on those dedicated agreements we're not currently seeing a lot of pressure in terms of renegotiating the pricing. It's only when we try to fill white space in the calendar and we want to grab some spot work for a short term interval that we see a differential on the pricing. But for most of our crews we're not saying that pressure right now.

Okay, great. And if I could squeeze one more in, one more question on kind of CapEx, am I fair to think that at this level of activity as you kind of exit the year that your maintenance CapEx is probably around $350 million as a baseline as we head into 2019 and then on top of that would be any growth? I just want to make sure I'm kind of thinking about that number correctly?

I think it's really too early for us to comment on exactly what that's going to look like or call out a number right now because of the changes in activity and some of the things that we're doing to try to tighten up maintenance CapEx spending. So, we just have to get back to you later on that.

Okay, thanks. I'll turn it back.

Your next question comes from the line of Tommy Moll with Stephens. Your line is open. Please go ahead.

Good morning. Thanks for taking my questions.

Good morning.

So, on the 53 upgrade opportunities that you have got left, how many of those rigs are currently idle versus active? And then for those that are idle, are we looking at roughly $15 million a piece CapEx to perform the upgrade? And then for those that are active, is it a similar level of CapEx or a lower level?

So, Mike is pulling up the numbers on which of the 53 are active right now. Yes, some of those 53 APEX rigs are currently working and then some are idle. If those rigs are currently working, they're a relative fit for the market. But some of those that are currently working – Mike just gave me the number. So, we have 32 of the 53 that are idle. But the ones that are working may only need to add a walking system. They may only need to add a high-pressure circulating system. So, you're talking about a $1 million to $5 million investment there depending on the rig. The ones that are idle may need a much larger upgrade in the range of that $15 million. And so again for us to do that we would want some kind of long-term contract that economically makes sense to do that. The good news is that we are in discussions with customers in 2019. The super-spec rig market is tight. We see demand for some super-spec rigs and we see that continuing into 2019 and we're very upbeat about the drilling business.

Is it fair to assume that the next batch of upgrades are most likely to come from the idle stack and then once that is depleted, there would be a meaningful leg up in terms of pricing power? Because when you get into upgrading an active rig, your payback calculation would look different, I would suppose, because it's not a function of zero gross margin today versus something under a contract but you're already generating a pretty good margin and therefore might need more incentive on the pricing side to perform the upgrade, is that fair?

So, without having the individual rigs schedule in front of me and just making some assumptions there, if an APEX rig is working today, it's likely to keep working. So, for those rigs that are working, we're not likely to bring them in and do any upgrades. They're likely to stay working in the condition that they are in and we probably be talking about the idle APEX rig and some major upgrades. If that becomes incremental to the rig count, we'd do that. So, you would have existing APEXs that would continue working and then as the market conditions continue to improve, if we're able to sign those long-term contracts for rigs in 2019, then those will be incremental to the rig count.

Okay, thank you. That's all from me.

Your next question comes from the line of Chase Mulvehill with Bank of America Merrill Lynch. Your line is open. Please go ahead.

Hey, good morning.

Hey, Chase.

Hey. I guess the first question, just keeping on the land rig theme, I was surprised to not see any new upgrades announced during the quarter. So, could you maybe just talk about the number of bids outstanding for major upgrades, how has that trended recently? Has that started to trend down? And if so, what do you think is driving the less number of bids, a lower number of bids out there today?

Yes, first off I wouldn't necessarily characterize them as bids. These are really discussions and negotiations between us and the customers. It's not necessarily that a customer goes up to bid and gets pricing. It is more of a discussion which is positive because we're talking about operators entering into long-term contracts at what we consider higher dayrates and so that's more than just a bid type situation. But I think the reason that we don't have more contracts to announce right now is really a function of the timing and where we are with the operators' budget cycle. The operators are working on their budgets right now and so when you get to the drilling department level of an operating organization, they likely don't have internal approvals yet to discuss the further rig adds, although we are discussion of what their potential plans are for next year. They've got to get to their budget cycle before the drilling departments have that level of approval. And so, I don't think we're not going to hear more definitive information from the operators until later in this year, early next year. But again this market is tight. Operators are in discussions with us now because they understand there is a queue out there and they understand if they want a rig, they've got to get in the line.

Okay. And if somebody were to come to you today and want you to upgrade, a major upgrade of one of your rigs, when would you be able to deliver it?

That first one from a discussion today would be available late in the first quarter or early second quarter.

Great. And then gross margin per day (sic) [rig margin per day] (45:08) was guided to be up $500,000 (sic) [$500 a day] (45:11), what's the OpEx component of that? Is OpEx kind of flat or is that going to be down?

In the drilling rig business we expect OpEx in the fourth quarter to be roughly level from the third quarter.

Okay. Great.

(45:30)

I'll squeeze one more in, can you just talk a little bit about leading edge super-spec dayrates? And then if that's actually starting to have an impact on kind of some of the lower-spec rigs and bringing those dayrates up yet?

So, what we're seeing in terms of leading edge and we said this at the last quarter that leading edge was around the mid-20s on contracts that we were signed for delivery in early 2019 and I would say that leading edge is still that mid-20s and pushing up a little bit from there. So, I think we are seeing from their mid-20 level without pinning down to a number that we still see those pricing levels from discussions particularly moving up from that mid-20 level.

Okay. Is this starting to have an impact on some of the high spec, lower spec rigs and pull those rigs as well?

Yes, there is no question that in the market as the pricing on the super-spec moves up, it's lifting the pricing on other rigs in the market and the tightness in the demand for the super-spec as well is I think keeping other rigs active through the rest of the year and we'll probably generate some interest for instance our non-APEX rigs in 2019.

Great. If you squint at those two dayrates that have the differential, has that narrowed?

I would say it hasn't narrowed yet but it's likely to move in that direction as we move into 2019.

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

Thanks.

Your next question comes from the line of Taylor Zurcher with Tudor Pickering Holt. Your line is open. Please go ahead. Taylor Zurcher - Tudor, Pickering, Holt & Co. Securities, Inc.: Hey. Good morning. Thanks. Andy, for the four spreads that you stack during Q3, could you give us some color as to which basins and plays those spreads were previously working? And then maybe more high level as we think about the four primary geographics, regions you operating in pressure pumping, those being Eagle Ford, Permian, Northeast and Midcon, are you seeing similar softness across all four or is the softness more acute in one versus the other?

So, in terms of spreads that we're not marketing today that softness is really around Texas and Oklahoma for the most part. But I think as we discussed we have the potential for recovery in 2019 because we're not seeing the drilling rig count slow down. On the contrary, we're seeing the drilling rig count for ourselves move up in the fourth quarter and that's going to drive an acceleration in that DUC inventory. And I am sorry, what was the second part of your question? Taylor Zurcher - Tudor, Pickering, Holt & Co. Securities, Inc.: That answered it. I was just basically just curious today if one region was softer than the other but that answered it. And maybe a follow-up, it sounds like at least on the dedicated side your pricing has stayed relatively consistent. I just wonder as you fill the white space in sort of the spot market what the delta is in pricing between spot market today versus some of your dedicated pricing today?

In terms of a delta in the pricing between what we're getting on dedicated and what we fill gaps in the calendar on spot, I actually think it's kind of hard for me to call out. I think it can vary within a range and I don't think I can give you a good number right now. Definitely the spot price is lower. There is a lot of competition there. That's a bit more challenging, but very pleased to see that pricing is essentially holding up with the dedicated agreements that we have. Taylor Zurcher - Tudor, Pickering, Holt & Co. Securities, Inc.: Okay, appreciate it. I'll turn it back.

The next question comes from the line of Blake Gendron with Wolfe Research. Your line is open. Please go ahead.

Hey. Thanks, guys. Wondering if we can get some clarity on the efficiency trends that you're seeing both on the drilling side and the pressure pumping side, appreciating DUC comments. The pushback that we've gotten from investors is that you're starting to see rig efficiencies kind of playing out here, I guess, offsetting that as maybe lateral lengths are starting to stagnant at the leading edge. You're hearing about pressure pumping spreads becoming more efficient and perhaps running into the rigs. So, what would you guys say just given you play on both markets, what you're seeing at the field level on both sides and maybe how does that follow through to the DUC count moving forward?

You know I think we have seen efficiencies improve in 2018 and we look at efficiencies in terms of how many stages can a spread do within a given time period, whether it's per month, per quarter, et cetera, and so how that's how we look at efficiencies and we have seen efficiencies improve. Some of that is driven by the move and the shift you're seeing primarily in West Texas to more zipper fracs. But when we do more zipper fracs, we're also consuming more horsepower per spread so it takes more horsepower on location to make sure that everything has the proper uptime to be able to do that because zippers is more of a continuous pumping operation than a non-zipper operation. Other basins have been doing zippers for a while, especially the Northeast, a little bit in South Texas. So, you're seeing the shift in the Permian, but I'm not sure how much you continue to see the shift past 2019. So, we'll have to wait and see how much gets consumed there. But again we are seeing that and it's been driven by the shift to the zipper, so we'll have to wait and see some commentary on E&Ps and how that moves for the rest of the year.

Okay. Great. And then can you just remind us what you guys have on the sidelines as far as horsepower goes? And then as we look into 2019 and that market improving, do you see the same number of nameplate active spreads going back to work or are you going to have add incremental horsepower to beef up those spreads or perhaps are you going to rationalize horsepower and consolidate to a fewer number of spreads?

So, I think the rationalization on our side occurred in the third quarter when we dropped from 25 to 1. But at the same time as we move into 2019, as we do reactivations, if those reactivations for a spread, if it was not doing zippers before and it's going to start doing zippers as we mentioned, it's going to have to have a little bit more horsepower per spread to be able to do that. So, I think it's kind of hard to project exactly what that's going to look like in terms of where those spreads may land, which operators, which agreements they're going to go into. So, I think it's a little bit early to talk about. But again as I mentioned, we don't anticipate working more than 21 spreads in the fourth quarter but we are in some discussions for early 2019 about some reactivations to get started in the year.

Awesome. That's helpful. Thanks, guys.

And your next question comes from the line of Ken Sill with SunTrust Robinson Humphrey. Your line is open. Please go ahead.

Yes, thanks. I was wondering whether I was going to get in here. So, just want to ask a question from the last time again. How much active horsepower do you have or what's the average horsepower per fleet now that you're down to 21 fleets?

Yes, we're not calling it out right now. I mean it's moving depending on where these spreads are working. Even the spreads – even the 21 spreads that we're working in the fourth quarter, if we're doing – we might be working on one type of pad where it's not a zipper and it might shift over to a different pad where it is a zipper and that could be in the same – for the same customer within the same agreement and then that's going to move the amount of horsepower per spread. So, it's something that we see shifting right now, even within dedicated agreements that we have.

I guess to the extent that you're moving to more zippers in the Permian, then we should just expect the average horsepower per fleet is going to go up a little bit from where it was on average for the first part of 2018.

I think when you look at it from an industry standpoint, as Permian increases the amount of zippers they're doing, it does require us as an industry to increase the amount of horsepower per spread.

Okay. And then just kind of parsing into the slowdown, you guys are looking at a 25% decline in revenue sequentially. How much of that is people actually saying they're slowing down because of capacity constraints or just we've exhausted budgets or it's just kind of it's been a long year; we're going to take some time off for the holidays?

You know it's a mix of all the above right now, but we're certainly not going to say that the capacity constraints aren't part of it. We think they are part of it but the majority of what we're seeing are E&Ps trying to stay within their budgets and their spending that they've broadcast to the Street and trying to hold back and they're doing that through seasonality, through slowing down at holiday periods here as we get towards the end of the year, et cetera. But we recognize there's capacity constraints in the Permian but we're seeing pull back across the U.S. and not just the Permian, and a lot of that has to do with budget constraints.

Yes, that's one that's been hard to figure out because a lot of people are saying they haven't seen much constraint yet but there's definitely a slowdown. Last question here is after you wrote off the 42 non-APEX rigs, how many non-APEX rigs do have left and how many of those are working versus idle?

So, in the fleet, that would leave us with 252 rigs, that's 198 APEX and 54 non-APEX. In terms of the non-APEX that are working, we have 17 non-APEX rigs that are working today.

Okay. Great. That's all I needed. Thanks.

Thanks.

Your next question comes from the line of Colin Davies with Bernstein Research. Your line is open. Please go ahead. Colin Davies - Sanford C. Bernstein & Co. LLC: Thank you. Just a question around what you've done around some of the variable cost for the laid-down or the idled frac fleets. Obviously, if you're talking about reactivations in the first quarter or early in the year, that may be a different strategy than if it's more related to Texas and perhaps a Permian ramp in the second half of 2019. Can you just perhaps give us a little more color on perhaps the people side and the variable cost?

Yes. So, as we've reduced the amount of activity that we had in the third quarter from the 25 to the 21, we certainly want to try to keep our costs in line. We do have turnover in this industry. That's not something that's just Patterson-UTI specific, but the industry has head count turnover that's still relatively high. The job markets are tight across the U.S. So, we can allow the turnover to bring our compensation cost down but at the same time we want to hang on to experienced personnel because we do believe that we have upside in 2019 and we believe it will be reactivating the spreads at some point in 2019. So, we are doing different things to manage that cost and the spending, but some of it is around head count. Colin Davies - Sanford C. Bernstein & Co. LLC: Yes. And then I was just intrigued by your comments around Directional. Just wondering whether there's perhaps any thoughts around whether the more structural pricing problem? I mean obviously the massive increase in drilling efficiency over the last few years makes it a challenge if you're being paid by the day rather than the foot. I mean is the more of a structural problem there in terms of the industry is mechanisms for pricing for directional services?

No, that's an interesting question and the directional industry has kind of moved back and forth between do we charge by the foot, do we charge by the day it's changed at different periods in time in the industry and it's really depends on how we have to be able to manage the risk in operations and what we have control over and what we don't have control over. So, I think we'll continue to look at that as an industry. I think that as I mentioned we think the pricing needs to come up in the directional drilling sector. With the super-spec rigs out there with the 7,500 psi circulating system, the flow rates are much higher. So, the wear and tear on the downhole equipment in the directional drilling side is higher as a result of that and I don't think we'll be the only ones that will be pushing for higher price to cover those additional costs. I am sure that others are seeing that materialize in their repair and maintenance cost this year as well with the increasing percentage of super-spec rigs across the industry. Colin Davies - Sanford C. Bernstein & Co. LLC: That's really helpful. Thanks very much.

Your next question comes from the line of John Daniel with Simmons and Company. Your line is open. Please go ahead. John Daniel - Simmons & Company International: Guys, thanks for putting me in keeping the call going. Andy, as you begin your 2019 budget for the frac business, can you speak to the decision to either rebuild some of the existing equipment or perhaps buy new equipment to replace legacy? And specifically, do you see any new equipment designs or component part technology which would warrant sort of a more methodical newbuild/replacement program.

So, John, that's a really good question. You might be a few weeks early in our budget process for us to be able to even answer that but certainly what the teams look at is what we think our cost of ownership is in terms of some of that technology. We've been testing various technologies that's been available to us as you know and trying to understand what the cost is whether it is the fluid-end, the power-end, transmission, new engine, et cetera. And so, as we do get into that budget process in the fourth quarter we will be looking at that but I think it's really too early for us to have that discussion. But overall again we will be looking at the cost of ownership, rebuild versus buying new for a complete pump trailer, rebuild versus buying new for individual components, and all those kind of things as we get into the budget cycle for 2019. John Daniel - Simmons & Company International: Okay. Fair enough. Just two more from me. I suspect it's safe to assume that fleet profitability across your company varies. So, when you move from 25 fleets to 21, are you able to specific idle your worst-performing fleets or you're simply dropping the fleets that's impacted by a specific customer slowdown?

I would say that in the market that we have today, this is really a customer-driven event. It's based on customers' budgets, customers' takeaway capacity in certain basins, and I would say as an industry we don't have a lot of optionality here on our side and that we really just have to kind of move with what the customers are doing and we have to respond to that as best we can and manage the cost side as we move into this fourth quarter. So, it's a bit of a challenging market knowing that we do have this activity slowdown in the fourth quarter driven by some customers more than others and yet there is the potential for accelerating activity again some time in 2019 and very likely in the first half of 2019 just because of visibility we have on the drilling side of the business. John Daniel - Simmons & Company International: Yes. Okay. I guess final one from me, you noted and customers have indicated the possibility they'll go back to work once they get new budgets. I'm just curious for those customers how would you characterize the price discussions? Are they trying to take advantage of lower prices now or do you tell them you need to pay a higher price for us to reactivate these fleets? Because you said in the release that you're not – basically you're not going to work fleets at current market conditions. I am just trying to understand as we think about Q1 into Q2 if we start modeling higher fleet counts should implicitly be assuming higher rev per fleet or would you put them back at current pricing?

I think those discussions are yet come. I think it will – some of that will depend on our side on how those negotiations go and how fast activity in the industry is ramping up. And so, I think it's kind of too early to really know what that's going to look yet. From my standpoint, unfortunate we're slowing activity in the fourth quarter, unfortunate that we've had to shrink from 25 to 21. But as we increase activity in 2019, which we strongly feel like we will, we want to focus on the margin for spread pushing pricing were we can. John Daniel - Simmons & Company International: Got it. Okay. Guys, thank you for your time.

Thanks.

Your next question comes from the line from the line of Brad Handler with Jefferies. Your line is open. Please go ahead

Thanks for squeezing me in, guys. Actually, I was trying to unqueue. My questions have been answered but thank you very much for the opportunity.

No problem. Thanks.

Your next question comes from the line of Daniel Boyd with BMO Capital Markets. Your line is open. Please go ahead.

Yes. Thanks. I think I am down to question 20 on my list but I will give it a shot. Given the focus that you guys have on cash and returns and really cutting things in pressure pumping during this period of weakness, I'm just wondering on those idle crews, are you able to use those at all or do anything to lower the repair and maintenance cost on the crews that you're working in this environment.

I would say that there is not, in terms of OpEx or CapEx spend for repair and maintenance, there is nothing that is going to shift what we have to spend on a per operating hour of usage for a piece of equipment in the fourth quarter. We are just going to try to manage what we can to keep the cost in line and not overspend in the fourth quarter.

Okay. And then how should we think about any reactivation cost on these fleets that you are idling when they come back to work in 2019?

We are going to take the opportunity on some of these spreads to just make sure that they are in condition to be able to be reactivated and I think that's just going to flow through the P&L over the next couple of quarters, so I don't think it's – we've got some of that built into those projections on the OpEx side already.

Okay. Great. Thanks.

Thanks.

And we have no further questions at this time.

Thank you. We like to thank everybody for joining us for Patterson-UTI's conference for the third quarter of 2018 and look forward to speaking with you as we report fourth quarter of 2018 in February. Thanks everybody.

This concludes today's conference call. Thank you for your participation. You may now disconnect. Have a good day.