Good day, ladies and gentlemen, and welcome to your Q4 2016 Patterson-UTI Energy Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we'll 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 introduce your host for today's conference, Mr. Mike Drickamer. Sir, you may begin.

Thank you, Nova. Good morning. And on behalf of Patterson-UTI Energy, I'd like to welcome you to today's conference call to discuss the results of the three and twelve months ended December 31, 2016. Participating in today's call will be Mark Siegel, Chairman; Andy Hendricks, Chief Executive Officer; and John Vollmer, Chief Financial Officer. A quick reminder that statements made in this conference call that state the company's or management's plans, intentions, beliefs, expectations or predictions for the future are forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995, the Securities Act of 1933, and the Securities Exchange Act of 1934. These forward-looking statements are subject to risks and uncertainties as disclosed in the company's annual report on Form 10-K and other filings with the SEC. These risks and uncertainties could cause the company's actual results to differ materially from those suggested in such forward-looking statements or what the company expects. The company undertakes no obligation to publicly update or revise any forward-looking statement. The company's SEC filings may be obtained by contacting the company or the SEC and are available through the company's website and through the SEC's EDGAR system. Statements made on 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 fourth quarter of 2016. 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 December 31, and then provide an update on our pending merger with Seventy Seven Energy, 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. Regarding the fourth quarter, as set forth in our earnings press release issued this morning, we reported a net loss of $78.1 million or $0.53 per share on revenues of $247 million. Total adjusted EBITDA during the fourth quarter was $44 million. Turning now to our pending merger with Seventy Seven Energy, we continue to make progress towards closing this merger, which we expect to be completed late in the first quarter or early in the second quarter. In January, we received early termination of the Hart-Scott-Rodino waiting period and filed our initial Form S-4 registration statement with the SEC. Recently we also completed an equity offering of 18.17 million shares, including the exercise of the underwriters' overallotment option. We intend to use the net proceeds from the offering of approximately $40 million to $70 million to fund the repayment of Seventy Seven's outstanding net indebtedness upon closing. At September 30, 2016, Seventy Seven Energy had $475 million of gross debt, and $23 million of cash for net debt of approximately $452 million. The proceeds received from the equity offering along with our revolver assure that we have sufficient cash available to repay the outstanding debt of Seventy Seven Energy. Any proceeds from the equity offering in excess of what is needed to repay the debt of Seventy Seven Energy and the transaction expenses will strengthen our own balance sheet and provide for increased financial flexibility. As previously announced, we also entered into an agreement with certain lenders under our revolving credit facility to increase the aggregate commitments by $96 million, subject to certain conditions, including the completion of the merger with Seventy Seven Energy, and the repayment and termination of the Seventy Seven credit facility. We are pleased with the increased financial flexibility afforded us by the increased liquidity. We believe the strength of our balance sheet will continue to provide us with a competitive advantage, a differentiator affording us opportunities that more financially challenged companies will not have. While our conditions are improving, the financial challenges for our industry are far from over. Reactivation expenses, upgrade CapEx, and increases in working capital will be uses of cash for the industry. With that, I will now turn the call over to Andy.

Thanks, Mark. In contract drilling, our rig count during the fourth quarter averaged 66 rigs in the U.S., up 6 rigs from the third quarter, while our rig count in Canada was unchanged at 2 rigs. As a reminder, our reported rig count is based on the average number of rigs generating revenue, which includes rigs on standby that are receiving a standby rate but not actively drilling. In addition to the six-rig increase in our U.S. rig count during the fourth quarter, our average number of rig on standby decreased by five rigs. Therefore, the increase in our active rig count was in line with the U.S. land industry rig count. Total average rig revenue per day for the fourth quarter was $21,640 compared to $21,870 during the third quarter. This decrease is a function of rigs that were reactivated, as well as the re-contracting of rigs that rolled off higher day rate term contracts. With the five-rig decrease in our standby rig count during the quarter, the proportion of days on standby decreased to 4% in the fourth quarter from 13% in the third quarter. Rigs on standby have very low associated costs. As a result of the significant reduction in the proportion of rigs on standby, total average rig operating costs per day during the fourth quarter increased to $13,770 compared to $13,180 during the third quarter. Without the decrease in the proportion of rigs on standby total average rig operating cost per day would have decreased as a result of fixed cost being spread over more operating days. As a result of these changes total average rig margin per day decreased to $7,870 during the fourth quarter from $8,690 during the third quarter. Included in average rig revenue per day and average rig margin per day…

Thanks, Andy. The pace of the recovery in our industry accelerated in the fourth quarter and has remained strong through January. With industry rig counts having approximately doubled from the trough, we are encouraged and believe 2017 will be an exciting year for Patterson-UTI for several reasons. First, after more than two years of scaling the business lower and cutting costs, we have been able to focus on growing the company again. Second, we continue to progress towards closing the pending merger with Seventy Seven Energy. This merger further solidifies our position as a leading high-spec drilling company. And with this merger, we will have one of the largest fleets in the U.S. pressure pumping business, a business in which scale provides efficiency. Finally, we will further demonstrate that we are a leader in walking rig technology with the delivery of the first rig with our new proprietary APEX-XC rig design. This pad-optimal design incorporates greater clearance for walking over and around wellheads on a pad and includes many of the features that are being sought by customers as they remain focused on efficiency and a high-quality execution. With that, I'd like to both commend and thank the hardworking men and women who make up this company. We truly appreciate your continuing efforts. Also, I'm pleased to announce today the company declared a quarterly cash dividend on its common stock of $0.02 per share to be paid on March 22, 2017, to holders of record as of March 8, 2017. Operator, we'd like to now open the call for questions.

Thank you. Our first question comes from the line of Angie Sedita of UBS. Your line is open. Angie Sedita of UBS. Thank you. Our next question comes from the line of Marc Bianchi of Cowen. Your line is open. Marc Bianchi - Cowen & Co. LLC: Thank you. Nice work on the new builds. Surprised to hear that the rates are up at that level at this point. Could you talk about where those are going? And maybe what it's going to take to get the rest of your super-spec rigs up to those kinds of rates?

Well, we certainly – we talked about this at the last earnings call that we see that the rig rates are going to increase as rigs continue to go out and we've seen that. You see that in the numbers that we discussed for the two new rigs that we're going to complete. And so, we were certainly encouraged with the favorable economics to complete these rigs. But I do believe that with WTI in the range that it's currently trading at today, that rig count continues to go up and rig rates continue to go up as well. Marc Bianchi - Cowen & Co. LLC: Okay. Maybe switching over to pressure pumping, I guess similar kind of question, you're seeing the 20% to 30% price increase on reactivating equipment that you said previously. What's the mechanism to get the rest of the fleet that was already in the field to see those kinds of price increases? I'm just wondering if there is any sort of timing on customer agreements and contracts that we may need to wait for or is it really just a function of what the market will bear.

It's really the supply and demand of the overall available active horsepower or the available horsepower in the market. And overall utilization is still not there for general pricing in pressure pumping. It's still at a level that we just don't consider sustainable. We were very encouraged by the agreements that we worked out with customers who needed additional spreads, where we were able to get within that target range of 20% to 30% for that incremental spread, but it's – we're still not at the level to push overall pricing in pressure pumping. But as we continue to activate spreads in the industry, we're pushing closer to those overall utilization levels in the industry. Marc Bianchi - Cowen & Co. LLC: Okay. Maybe just one more if I could. The margin improvement that you talked about for pressure pumping is also pretty impressive, and I know you guys, incremental margins are probably not as useful these days just because of all the sand everybody is pumping. But if we think about what that implies here, it looks like sort of a 60% type incremental in the first quarter. Is there anything unusual going on in the first quarter that's contributing to that margin leverage that would kind of keep that from being the case going forward? Or how should we think about that as we roll past first quarter?

In the first quarter, this is really a function of our increased activity with the new spreads that's coming out and barring any operational delays based on things that are out of our control, we expect these margins that we're currently projecting. Marc Bianchi - Cowen & Co. LLC: Great. Thanks very much. I'll turn it back.

Thank you. Our next question comes from the line of Kurt Hallead of RBC. Your line is open.

Hi. Good morning.

Good morning.

Good morning, Kurt.

Let's see, where to start here. So, in the context of the industry being short on super-spec rigs, and the fact you guys are able to get kind of a low-20s to mid-20s day rate on this activation. Can you put that in perspective? Are we going to have to see a new round of new builds here going forward from an industry standpoint, maybe start there? And does this kind of new day rate for these rigs act as a – if you will, an upward pull on the rest of the industry? What's your perspective on those two things?

Certainly, we see it as a positive that we were able to get these day rates for completing these new build rigs. It's a positive for us, it's a positive for the industry. We don't have any plans currently to build any other new rigs. And overall, I think day rates have to come up further before we seek or complete new builds. But I'm encouraged by the fact that the rig count continues to move up. And I think that because of that pricing in high-spec rigs it does continue to move up.

Okay. And then the – thanks for that. And then the follow-up I'd have would be on the frac side. And coming around to the prospect to activate fleets at a $1 million to $3 million run rate, we obviously have heard from a much larger player that that number is kind of for them more like $10 million; so big, big discrepancy there. Just trying to get a better feel for when you guys bring this out, I guess, your – does it imply to us that your equipment is in great shape and it really doesn't take much to bring it out of the yard or there's something else going on that enables you to have a lower cost?

I can't speak to anybody else, but our particular equipment is in good shape. The costs that we have associated with bringing out equipment, which has been $2 million so far per spread and will be about $3 million on average for all of our spreads is really based mostly on labor, but you've got some OpEx involved, you've got some CapEx involved. But in general, our fleets are in good shape and don't require any change from the existing technology that we're using.

And then on the – yeah. Go ahead, Mark.

We also have a relatively younger fleet than some of our competitors and that also helps us a little bit too.

Okay. That's great. And then one final follow-up on that front. You indicated in the past that you would need to see pricing 20% to 30% above whatever the prior points were for you to activate equipment. So clearly, I think we can infer that that's what you're getting. Now in that context, is it also safe to assume that it's not only positive EBITDA, but it's a substantially positive operating margin that you're getting by activating these frac fleets?

But certainly positive on the EBITDA, because we were positive for all of 2016 – we're getting closer in terms of overall net, but I'll just say in general pricing is still not a level that were happy at in pressure pumping. We're pleased that the economics made sense for us to activate these spreads, but we would like to see pricing come up more.

Okay, great. Thanks for that. Appreciate the color.

Thanks.

Our next question comes from the line of Chase Mulvehill of Wolfe Research. Your line is open.

Hey, good morning.

Good morning, Chase.

Good morning.

So, I guess a question on pressure pumping, once you close the Seventy Seven Energy deal you have – about 1.5 million horsepower, so you got some really good scale – is there – we see some of these pure play public pressure pumping companies trading at some pretty racy replacement cost, would you entertain the idea of potentially spinning off the pressure pumping business?

No. Right now, we're trying to complete the merger with Seventy Seven. So, the first focal point for us really at this point, at this stage is finish the merger. We will think about all the possible alternatives, but not certainly until we get to a point where we completed our merger.

Okay, all right. And then – we've heard a lot of anecdotes about increases in frac pricing over the last few months – or sorry, frac sand pricing over the past few months, could you talk about your contracts and when they – if you have them and when they might re-price and things like that?

We're continuously discussing and negotiating with sand suppliers. We do see sand pricing moving up in 2017 and it's really specific on certain grain sizes. Without going into the detail, we're comfortable with the contracts that we have in place today and our bigger concern in general is supply, but we're comfortable with the pricing we're getting and we're comfortable with the supply that we have.

And so, what are you seeing for price increases? How much are they up off the bottom?

It depends on the grain size. It's varying by different sands right now.

Okay. You care of the 40/70 – I mean, we're talking 10% to 15%, or more than that?

I would say that we have good contracts in place and we're still very competitive in what we're buying sand for and, therefore, what we're passing on as cost to the customers.

Okay. Awesome. That's all I have. Thanks, Andy. Thanks, Mark.

Thank you. Our next question comes from the line of Brad Handler of Jefferies. Your line is open.

Thanks. Good morning, guys.

Good morning, Brad.

I guess, I'll focus on the drilling side. And, yeah, it's great to see you guys are able to get something as high as the mid-20s for new build contracts, and I can certainly speak to the demand for that super-spec, as you guys have been talking about for a long time. I guess, I'm curious what it should – what it tells us and what you are, therefore, anticipating about some of your older APEX rates; so, walk us through, perhaps, reasonable rate disparity over time or something that would make sense. I mean, if we note that your APEX SCR rigs are not – just over 10% utilized; I guess, 5 rigs out of your 42 rigs are working, for example. So, what does it tell us about customer demand and, perhaps, walk us through how you see a landscape for those – for the balance of your APEX fleet, if you will?

Brad, I think it's very similar to previous cycles that we've seen in the industry, where the leading-edge technology will lead in the pricing, but it lifts all boats in general. And so, while we still have some APEX 1500 horsepowers that aren't back to work, yet, we see that this leading-edge pricing on the completion of these new builds lifting the pricing on those APEX rigs when they do go back to work.

Presumably this is happening – I don't know how you feel about this relative to other cycles that you're – if you're seeing rate improvement before the utilization, it's obviously saying something about the preference for technology; or, at least, so it would seem, and maybe that's a little bit different than prior cycles, or you would argue that's not – again, it's pretty much the same.

I would argue the same argument I've been making for a couple of quarters now, is that when the rig count goes up in high-spec rigs, that pricing goes up with it. It's just – there's that type of market demand for the high-spec and the super-spec of the high-spec rigs out there.

Fair enough. All right. A follow-up, still on the rigs, but as you get deeper into your fleet in terms of putting rigs back to work, do you expect we'll see the wobble of reactivation costs become more relevant? I understand you've taken care of rigs and all of that, but we have at least seen one of your competitors note that there are some costs related to kind of getting them back to work. Is that something we might keep an eye out for; again, it may be as you get deeper into reactivating rigs?

I would take you back to what we explained in terms of our total CapEx projection for 2017. So, of that, we said that $115 million was for the rig upgrades and the new builds, and only a small part of that is for the new builds. A majority of that is for the upgrades. So, we think that we have that budgeted for 2017.

And then, not from an OpEx perspective, again, just whether it's re-crewing or if it's items that you're expensing in the process, is that – again, is there something you think might weigh on the operating costs as you go forward?

Well, on the OpEx side, you certainly have the labor and you're talking about adding rig crews two weeks to four weeks of carrying costs before the rig starts up. But we've been seeing that really for the last two quarters, now.

Anyway, so nothing different. Okay. Great. Thanks for the answers, Andy.

Sure.

Our next question comes from the line of Marshall Adkins of Raymond James. Your line is open. J. Marshall Adkins - Raymond James & Associates, Inc.: Good morning, guys.

Good morning. J. Marshall Adkins - Raymond James & Associates, Inc.: Just curious, we're building the two brand new rigs here. Why not reactivate or upgrade some of the 1500s you have right now, rather than building brand new? Is it because you already had the parts around?

So, I would say it's a combination of a few factors. So, one, we had inventory from 2014 when we had strong plans for new builds. So, we had inventory that we'd already spent cash on. So, we were able to spend some incremental cash to get these rigs to work. The other is really just the demands for these two specific types of rigs. We were essentially booked out on APEX-XKs, and we had a customer who likes APEX-XKs and was willing to help us finish off his rig. In the case of the APEX-XC, we had a particular customer that has a very large multi-well pad, a larger number of wellheads than a normal multi-well pad. And the APEX-XC, from a technical standpoint, is a very good solution for his particular needs. J. Marshall Adkins - Raymond James & Associates, Inc.: Okay. So, the other 39 rigs you have to kind of upgrade, are they going to be more like the XKs or the XCs or something totally different?

Well, they're a little bit different from the XKs and the XC is really the next step in our original 300 Series, if you look at the rig numbers on our website. But we anticipate that these other rigs will eventually go back to work as well. And like I mentioned earlier, we think that the pricing that we're getting on the completion of these new builds lifts the pricing of these rigs as well as the market continues to tighten. J. Marshall Adkins - Raymond James & Associates, Inc.: All right. Last one on this, what happens to the SCRs you have left in the fleet. Do you see those potentially going back to work over time or do we see as parts and pieces of the upgrade and refurb the fleet?

No, we've kept rigs on our marketed list on our website that we believe can all eventually go back to work depending on what the total industry rig count is at a certain time. We don't see these as parts for other rigs, we do see these as complete rigs that are eventually marketable. The SCR rig is going to be for a different type of customer than APEX-XK, but depending on what the future rig count is, there's certainly a market for these rigs. J. Marshall Adkins - Raymond James & Associates, Inc.: So, if we get back to 1,100, 1,200 rigs running then those SCRs you think are working again, basically.

Yes. Yes. J. Marshall Adkins - Raymond James & Associates, Inc.: Okay. Thanks, guys.

Our next question comes from the line of Blake Hancock of Howard Weil. Your line is open.

Thanks. Good morning, guys. Andy, I wanted to talk on the pressure pumping side a little bit. Last quarter, you kind of talked about, kind of the incremental revenue you could have put through on the crew outside of the guidance. I just wanted to see – maybe help us understand the 1Q schedule on pumping and given the two crews that you're reactivating, how much more could you actually put through, what you have active today before the one crew becomes active in 2Q, just trying to gauge what the upside will be on 2Q without the reactivation?

I think it's safe to say that that our calendar really doesn't have much open space in it right now. It's driven us to that point where we were able to activate – in the process of activating and have activated three spreads since mid-December. So, in terms of the calendar and the open space, I don't think we have much left. There is always the potential as the new crews get started that their efficiency improves and the number of stages per day per week improves over time, but I would say that's the upside right now.

Okay, great. And then on the drilling side, being sold out in Texas and Oklahoma, a lot of those rigs are still in the spot market per se, are you getting the option to increase those rates at your will, are you still having to wait for kind of the industry to continue to catch up?

I believe that we have the ability to move rates on rigs where we are not locked into contracts, on pricing agreements that extend for long periods of time. And so we will see that. The fact that we are essentially sold out in Texas and Oklahoma means that the industry is tight and industry pricing is going to move up, because rigs continue to go out and so pricing is going to move up as rigs continue to go out.

All right. Thank you, guys.

Our next question comes from the line of Timna Tanners of Bank of America Merrill Lynch. Your line is open.

Hey, good morning.

Hi, Timna.

Good morning.

I wanted to ask two things. One was, if you could, I didn't hear it, but I was wondering if you could kind of spell out some of the main components of the longer-term $3 million cost per frac spread versus the $2 million that you're seeing now?

So in general, when we activate a frac spread, the largest costs that we have – and remember that the $2 million and the $3 million average includes labor OpEx and CapEx. So, labor is the largest cost there. As we activate spreads, we're activating the spreads that cause us the least amount to get out. And as we move through the fleet, we'll be spending a little bit more dollars in terms of CapEx whether it'd be more fluid ends or maybe a transmission rebuild, but that's where the differential in the dollar value comes.

So, you're reactivating the ones that are – and the highest quality is the best way to go and as you reactivate further fleet – further parts of the fleet it will be the ones that need a little bit more work, is that what you're saying?

Correct, exactly. So, we're activating spreads that are costing us the least amount in the beginning, and we'll move into the spreads that are going to cost us a little bit more as we continue to have the opportunity to activate.

Makes sense, okay. The other question was on the drilling side, I didn't hear if you mentioned on the contracts for the new rigs if there was a duration amount in general, if you could comment. I know last quarter you said that still customers were wary about planning longer-term contracts. If you can comment on contract duration in general as well.

Yeah. So first, let me just comment on contract durations in general. We still believe that in general in the industry, as rigs continue to go out, their pricing continues to move upward. Therefore, we would like to avoid any types of long-term contracts. For the two new build rigs that we're completing, we have one rig that has a 6-month contract and one rig that has a 12-month contract. But we believe that this is still economically favorable, to complete these rigs.

Cool. All right. Thanks again.

Thanks.

Thank you. Our next question comes from the line of Ken Sill of SunTrust.

Yeah. Good morning. So, I was a little surprised on the duration of those new contracts, but I kind of understand reactivating something you spent the money on going into an up market. I'm wondering if you could give us some idea, where rates would actually need to go to go out and actually order the parts and build a new rig. I mean, you're kind of in the low $20,000 to $24,000 a day right now, I mean do we need to see rates back in the mid-to-upper 20s to build new rigs or do you think that is – and what kind of contract term would you want to do that.

I think to build new rigs from the ground up, you need to have at least the mid-20s and the market's not there yet, but the market continues to improve. So, as I mentioned earlier we don't have any plans today to build any or complete any new rigs, but we'll have to wait and see what the market does in the future as well.

And if we had mid-20s rates, we'd be looking for some duration greater than the duration we accepted on those two rigs we talked about.

Mark, I would hope so. Another question, pressure pumping's heating up, you guys are pretty satisfied with your capacity on sand. What about issues, what's going on in the Permian? Are there going to be issues on the last mile, given some of the well sizes and sand volumes we're seeing out there, and how do you guys plan to address that?

In terms of the last mile, we're doing – we have several different efforts in managing logistics. We use third-party trucks, we also have our own trucks. Now, we were not using our own trucks in 2016. But as the activity has been increasing, we have started to reactivate some of our own trucks as well. So, we believe that we're still managing that well. And I don't foresee any problems for us in particular in this last model with the combination of third-party trucking and our own trucks.

That's encouraging, although my sympathies go out to whoever is managing the trucking fleet on the labor side. Well, that's all, I'll drop and I'll let some other people ask some questions. But – yeah, congratulations on making it through the tough patch.

Thanks.

Thank you. Our next question comes from Angie Sedita of UBS. Your line is open.

Thanks, guys. Good morning.

Good morning.

Hi, Angie.

Oh, press one more time. So, on the Seventy Seven assets, I know you can't say, Mark, but could you at least remind us how much of their equipment both land and frac is in the field today?

I'm sorry. Can you repeat that? How much of their equipment is what?

Is working.

Is in the field today for both frac, pressure pumping and land, how much is actually operating of their equipment?

I don't think we have an answer for that directly. That kind of changes week to week for that company.

I think that information should properly come from Seventy Seven at this point.

Okay. Okay. That's fair enough. I understand. And then on the rig count, obviously, it's been very stronger in the first half and I think stronger than any of us would have assessed it. And I know you have limited visibility. But any thoughts on the pace of the rig count as we go into the second half of 2017, if you would – naturally, you think it would start to flatten then slow as we seasonally see that slowing or is there any reason to believe that that pace will continue to be strong in the second half of 2017 based on any of your conversations.

Angie, I've historically only given some guidance for the next quarter and your comments are correct that we certainly will see a strong – the trend's continuing strongly in this next quarter. Looking out for the rest of the year, we're not seeing any signs of the trend changing at this point. We do read analyst reports, some of which are more optimistic, some of which are less optimistic about the second half of the year. But frankly from what we're seeing from our customers, we just see a continuing trend.

Okay. Okay. And then on cost inflation that you're seeing, whether it be labor, logistics, can you talk about where you're starting to see some cost inflation, and where you think you could see incremental bottlenecks that would go into 2017.

Yeah. So there are some areas of cost that I think the entire industry is sensitive to. In terms of labor on the rigs, we're not seeing the cost pressure yet. In terms of labor and pressure pumping, I think we're going to start to see some pressure on labor, and in general we're going to have costs related to labor for the recruiting, the on-boarding and the training that we have to do to get people back to work. So that's kind of what's happening in the labor front. In terms of materials, I think some of the materials and supplies that we use in both drilling and pressure pumping will start to move up in terms of cost, but I'm also confident that we're able to manage those, but with activity moving up, in general, our pricing moving up, suppliers' pricing is going to move up a bit as well. In terms of sand, as I mentioned earlier, we see sand pricing moving up. We see it more so in certain grain sizes than others where supply is tight. But I think, at the same time, we'll also see mines improve production in those grain sizes as well, and the availability as we go into the year. And so, we have agreements and we have discussions and negotiations with multiple sand suppliers in multiple basins to ensure that we have the supply and – so that we can do our best to ensure that there is some cost competitiveness out there for us as well. But overall, the market is improving; the rig count continues to go up. I'm certainly encouraged by how fast things are moving out of the gate in 2017. In general, in the industry, I think that we can't activate frac fleets as fast as demand is out there, and so that's allowed us to get the pricing improvements on the incremental spreads that we're activating and the industry is likely building DUCs as a result of that. So, that's kind of how I see things playing out right now.

Great, thanks. That's helpful. I'll turn it over.

Thank you. Our next question comes from the line of John Daniel of Simmons & Company. Your line is open. John Daniel - Simmons & Company International: Hi, guys. Thanks for taking my call. Andy, let's start with this one. What percent of your frac fleets work for customers who self-source sand and chemicals?

We do have a number of spreads that work for customers who source their own sand. We have, also, spreads that work for customers who may source their own chemicals, but not their own sand; but, we don't, in general, get into the details of what those percentages are, and they do change month-to-month. John Daniel - Simmons & Company International: Okay. Will the two fleets that go to work, the ones that you're reactivating, go to customers that self-source?

Offhand, I don't believe they do. John Daniel - Simmons & Company International: Okay, all right. How about – for the Q1 revenue guidance for pressure pumping, can you tell us how much of the increase is associated with the two fleets that have been reactivated? I'm trying to distinguish between what's price and what's new work.

Yeah. I would say the majority of the improvement is coming from activity. And certainly, we've got two new spreads in Q1 that are adding accretive pricing there, but the majority of the improvement is coming from activity. John Daniel - Simmons & Company International: Okay, all right. Two quick ones, last one – well, two. Rough estimate for fluid end consumption, sort of either Q4 or 2016, either the dollar cost or just the number of fluid ends consumed on the work completed?

Without getting into the details of fluid ends and the consumption, we mentioned in the financials that, pressure pumping, we're allocating $75 million for fleet activations and maintenance. And so, that maintenance will include fluid ends and you've got our fleet activation costs out there; so, you can kind of see what some of that might be. I am encouraged by, for instance, the fact that in our move to using a certain percentage of stainless steel fluid ends, for instance, the cost of stainless came down over the last couple of years; not in relation to oil field or oil field activity, but more in relation to the cost of nickel in the stainless blend. So, as we move to, for instance, stainless, we're not paying large incrementals for those particular fluid ends. John Daniel - Simmons & Company International: Okay, all right. Just last one here, then, Andy, and going back to sand for a moment given the tightness that we're seeing in 40/70 and 100 mesh, at this point, is Patterson being approached by any start-up sand mines? Can you just talk to us about what you're seeing in terms of new people emerging, and discussions, if any, with – in terms of sponsoring or working with potential start-ups?

I think it's safe to say, with us having 1 million horsepower, and in post-merger 1.5 million horsepower, that everybody calls us. So, I don't think there is any sand producer in the U.S. that doesn't contact us right now. John Daniel - Simmons & Company International: I'm not talking about the existing ones. I'm talking about what visibility you might have with respect to new mines emerging this year.

Yeah. So, we're getting contacted by individuals who are looking to start new mines as well. And so, that's why, while sand supply is a big concern of mine, we are hearing from individuals that are looking at starting production in sand that's not currently being produced. John Daniel - Simmons & Company International: Okay.

So, I won't get into the details of what we might or might do. John Daniel - Simmons & Company International: But it's happening; that's what I was trying to drive at.

Yeah. So, yes, we concur that it is happening. John Daniel - Simmons & Company International: Okay. That's all I needed. Thanks, guys.

Thank you. And we have a follow-up question from the line of Ken Sill of SunTrust.

Yeah. I was interested in your comment that demand for frac is going up faster than you can reactivate your fleets, and that's driving pricing. So, how far out is your active fleet booked and when should we expect to see – excuse me, pricing get better for those spreads?

Yeah. My comment in terms of the reactivation of frac spreads and it's hard for the industry to keep up was really more of an industry comment, not so much related to us, and it's based on discussions with customers; and, it's what drove us to be able to get the incremental pricing on the incremental spreads that we're putting out. But overall the utilization of the industry still has to improve before we get wholesale pricing. When we look at our overall utilization at the end of the first quarter and going into the second quarter, we're going to be at about 60% utilization and really pleased to see that number for a change. As rig count continues to go up in 2017, I think we will see further additions to active fleet in terms of pressure pumping and improvements in the overall utilization. And at some point, at a certain rig count, you're going to see the ability for pressure pumping pricing to move up higher across the industry. So we're certainly encouraged that we're going to be at 60% utilization in Q2. We'll have to wait and see what the rest of the year looks like.

And one final question on the pressure pumping side, how much of the work in the Permian and Oklahoma is 24 hours, I would assume they kind of need to move that way if they're not there already. But I'm just curious as to where that stands now?

So, I can only speak to us and majority of our work over 90% is 24-hour operation. Now, some maybe 24-hour five days a week, some may be 24-hour seven days a week, but the majority of our work is 24-hour operations.

Thank you.

And sir, I'm showing no further questions in the queue at this time.

Okay. Well, then we'll thank everybody who participated on the call for their participation and look forward to speaking with you as we report first quarter in April. Thanks, everybody.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the call. You may now disconnect. Everyone have a wonderful day.