Good day, ladies and gentlemen, and welcome to the Patterson-UTI Energy, Incorporated Fourth Quarter Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. As a reminder, this conference may be recorded. I would now like to turn the conference over to our host of today's call, Mr. Mike Drickamer. You may begin.

Thank you, Tanya. 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 12 months ended December 31, 2015. Participating in today's call will be Mark Siegel, Chairman; Andy Hendricks, Chief Executive Officer; and John Vollmer, Chief Financial Officer. Again, just a quick reminder 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 statements. The company's SEC filings may be obtained by contacting the company or the SEC and are available through the company's website and through the SEC's EDGAR system. Statements made in this conference call include non-GAAP financial measures. The required reconciliations to GAAP financial measures are included on our website, www.patenergy.com, and in the company's press release issued prior to this conference call. And now, it's my pleasure to turn the call over to Mark Siegel for some opening remarks. Mark?

Thanks, Mike. Good morning and welcome to Patterson-UTI's conference call for the fourth quarter of 2015. We are pleased you are 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 I will turn the call over to Andy Hendricks who will share some detailed comments on each segment's operational highlights, as well as our outlook. After Andy's comments, I will provide some closing remarks before turning the call over for questions. Turning now to the fourth quarter, as set forth in our earnings press release issued this morning, we reported a net loss of $58.7 million or $0.40 per share on revenues of $339 million. Total adjusted EBITDA during the quarter was $98.5 million, and we remain EBITDA-positive in all three of our business lines. Our financial position remains strong. Our cash balance at December 31 improved to $113 million from $76 million at September 30, and our $500 million revolving credit line remains fully available. With that, I'll now turn the call over to Andy.

Thanks, Mark. In contract drilling, our rig count averaged 88 rigs during the fourth quarter in the U.S. and three rigs in Canada compared to 105 rigs in U.S. and four rigs in Canada during the third quarter. During the fourth quarter, total contract drilling revenues were $202 million, including a $9.2 million of revenues from early contract terminations. These early contract terminations positively impacted our average rig revenue per day of $24,240 by $1,100. Excluding early termination revenues, average rig revenue per day during the fourth quarter would have been $23,140, which is unchanged from the third quarter. Total average rig operating cost per day decreased $940 during the third quarter to $12,640. Approximately a third of this decrease is related to cost savings with the remainder due to a higher proportion of rigs on standby. During the fourth quarter, the average number of rigs on standby increased to 12 from 10 in the third quarter. Rigs on standby have very little associated operating cost, and therefore, the increased proportion of rigs on standby during the fourth quarter reduced our average rig operating cost per day. Excluding the positive impact from early termination revenues, total average rig margin per day was $10,500 compared to $9,560 during the third quarter. At December 31, we had term contracts for drilling rigs providing for approximately $710 million of future dayrate drilling revenue. Based on contracts currently in place, we expect an average of 59 rigs operating under term contracts during the first quarter and an average of 46 rigs operating under term contracts during 2016. Looking forward, we have limited visibility into activity beyond the current quarter. We expect the continued weakness in commodity prices will lead to further rig count reductions across the industry. As such, we expect our rig counts…

Thanks, Andy. 2015 was a brutal year across the energy sector. Crude oil prices fell from a high of $105 in the third quarter of 2014 to a low of $34 in December 2015. The pressure on oil prices has not abated, as oil prices recently reached a low of $26 in January. Given current commodity prices and the pursuant expectations for reduced E&P capital spending, 2016 is likely to be even more challenging. And we do not expect this to change until commodity prices improve. Last quarter we discussed that the industry had reached a point where it was Darwinian, and the weak may not survive. We believe the industry is becoming increasingly bifurcated between the financially weak and the financially strong. The financially strong, such as Patterson-UTI, are seen as survivors, while those that are financially weak may not survive at least in their current form. We expect that asset sales and reorganizations as well as equipment attrition due to the lack of maintenance will impair the ability of some companies to respond during a market recovery. Despite market conditions we remain confident in the long-term prospects for our company. With 161 APEX rigs and more than 1 million horsepower of pressure pumping equipment, we have the kind of high quality equipment that we expect to be in greatest demand during a recovery. With that I would like to both commend and thank the hardworking men and women who make up this company. And I want to tell them that I appreciate your efforts during this challenging market environment. I am also pleased to announce today the company declared a quarterly cash dividend on its common stock of $0.10 per share to be paid on March 24, 2016, to holders of record as of March 10, 2016. Operator, we'd now like to open the call to questions.

Certainly. We do have our first question from Byron Pope. Your line is open.

Morning, guys.

Morning.

It feels like we're going to get a really good feel this year for what acreage is really core to E&P operators. And so as I think about – it seems as though the utilization for your APEX rigs has held up much better than the overall U.S. land rigs on average. And so as we think about the 59 and 46 rigs that you have term contracted for Q1 and for 2016 respectively, is it fair to think that it's largely concentrated among your APEX-XKs?

It's really by basin. And certainly a number of the XKs are working, but also some of the earlier APEX are working as well.

Okay. And then on the pressure pumping side I think I know the answer to this, given that you guys don't like to really split out details on the two regions. But of your half the fleet that – it's currently idled or stacked, is it skewed toward one of the two regions? Or fairly balanced between them?

It's a mixture of both. We have the challenge of commodity prices in both regions, whether it's WTI in the Texas region or natural gas prices in the Northeast.

Okay. Thanks, guys.

And our next question comes from James West. Your line is open.

Hey. Good morning, guys.

Good morning.

Andy, I know we talked about this on the last call, but the market, at least the big four companies had maintained, at least, mostly price discipline as of – through the, I guess the end of the third quarter. Has that continued as we've had this next round of oil prices coming down, and with a lot of term contracts starting to roll off? Are you starting to see your main competitors on the AC rig side becoming say, less disciplined, try to hold market share and becoming more, I guess, more willing to take much lower rates?

James, I wouldn't say there's been any real change other than it still remains a very competitive market. We have the situation of term contracts. And certainly as we progress through 2016, some of these term contracts will be rolling off, and we'd like to think that a portion of these are going to work at whatever the market rate is at the time. But we do expect it to still be very competitive.

Okay. And then I know, Mark, you talked about the bifurcation of the industry right now both from a pressure pumping and the land rigs side between financially sound companies and those that are becoming or will become distressed here shortly. Are the customers also bifurcating their work and shifting more work towards companies like yourself which have a better balance sheet?

I think I'll turn that to Andy.

So, I wouldn't say that the balance sheet per se – the company impacts who's getting work right now.

Okay.

It's still a highly competitive market, especially in the pressure pumping business. There're still a number of companies out there. What we said before and what still holds true is the pricing, in general, in pressure pumping industry is just really unsustainable. It's too low. And that's why you see us stacking 140,000 horsepower since the beginning of the year. But I wouldn't say people are looking at balance sheet per se. I think pricing is the primary driver of most operators' decisions right now when it comes to services. But there is also an element of service quality, and that's partially what's driving our results as well. Our teams have shown historically over the years that they're very competitive when it comes to operational efficiencies at the well site. And I do believe that's one of the reasons why you see our margins holding up, relatively speaking, in a very difficult market.

Okay. Great. Thanks, guys.

And our next question comes from Marshall Adkins. Your line is open, Marshall.

Yeah. Morning, guys. The thing that jumps out of me is how well you all are doing in the pressure pumping side from a margin perspective. So, Andy, give me a little bit of color on why you think that – there's a lot of guys that are negative margins, negative EBITDA at this stage in that area and you're still putting up respectable margins given the condition. How is it you're doing that? And again, you guided to margins holding in. How can you continue to put up this much better than average result in that space?

So, I'll give you what I believe are a few different reasons why our teams have done so well. And the first is you've got to kind of roll back to the clock to – in times we're busy and how well we performed even in times we're busy and the margins that we are posting in. So, our margin degradation from the peak may have been relatively the same as others, but we are doing better back when the industry was doing better as well at the same time. But part of the reasons our margins were doing better and part of the reasons they're doing better today is the concentration of our scale. We have 1 million horsepower in total, granted we stacked a little over half at this point. But with 1 million horsepower, we're in the Texas region and in the Permian Basin and we're up in the Northeast. And we compete against companies that are similar in size who are in multiple regions, and maybe even multiple countries, and I think that scale helps us out in the regions. Logistically, cost structure, various reasons.

Is there a difference on equipment as well?

Our equipment is relatively young. The average age of our equipment is still only about four years. That probably helps a bit. And we continue to maintain our equipment. We still invest maintenance capital on equipment to make sure that we're providing the absolute best service quality that we can for the customers.

One last unrelated follow-up from me. We're looking at oil recovery going into 2017, and we think cash flows will be there for – the rig counts are potentially double in 2017. I'm curious as to how you think the industry could possibly do that? I mean, are we going to be able to re-attract the people and as the industry is set up to see a doubling in activity, if the demand is there in 2017?

So, we certainly would like to buy in through your view. It's difficult from where we stood today to know if that's actually going to happen. But we are planning for an eventual recovery just because we've tried to maintain some of the key positions of leadership in the company and because we have the balance sheet, we can do that. And like maintaining some of the key leadership positions, it makes it easier to put the company's growth back into place when an eventual recovery does happen. But I think let's also speak about the labor market. If you look at the labor market that we had back in 2009-2010, it was very different in the country. Today, I think – we talked about all the equipments that's on the sideline but I think it's going to be tougher to pull some of the labor back in and we're going to see tightening on the labor side before we see tightening on the equipment side in an eventual recovery.

Makes sense. Thank you, all.

Thanks.

And our next question comes from Jim Wicklund. Your line is open. James Wicklund - Credit Suisse Securities (USA) LLC (Broker) Good morning, guys.

Hey, Jim. James Wicklund - Credit Suisse Securities (USA) LLC (Broker) We don't know how long this is going to last. We don't know how long it's going to – of this is going to be, all that kind of stuff. Does consolidation make sense in any of your markets in this type of environment?

Jim, we're always looking for opportunities. And as you know, we've had a long history of doing consolidations. And so, we expect that with this downturn and kind of the more prolonged and the deeper it is the larger the number of those opportunities there will be. That said, whether those opportunities are ones that we're going to find attractive is really a question I don't think any of us can answer at this time. James Wicklund - Credit Suisse Securities (USA) LLC (Broker) With the consolidation potential for the industry, do you think it would be better for the rig side or the pressure pumping side of the business?

I couldn't really – I don't have a view about that. James Wicklund - Credit Suisse Securities (USA) LLC (Broker) Okay. And my follow-up, if I could. You guys have opened an office a couple of years ago. Internationally, you looked at some of – weathered this stuff (22:04) a couple of years ago. Andy, you had said a lot of the future of the company is probably going to be international. Are there any opportunities that you see that are coming up internationally because of the slowdown that might not have been before? Is that market looking more encouraging or less encouraging to you?

Well, we haven't made any change to our plans for international expansion. We're very pleased with our position in North America today. And so, we just think that international is part of future growth of the company but its long-term plans. So, we're not making any changes to the plans. But certainly, as everybody knows, the international markets are experiencing some of the same challenges that the North American market is right now, too. So, it's still a long-term plan. James Wicklund - Credit Suisse Securities (USA) LLC (Broker) Okay. Thanks, guys.

And our next question comes from Ole Slorer. Your line is open.

Thank you. So, let me ask my friend James' question for him. So, are you going to merge with Nabors?

Ole, such a nice question. Thank you so much.

Okay. Let's move on to the next one. So, you're in pressure pumping and drilling and you're doing pretty well in both. As you look into the trough of the cycle and God knows what it looks like on the other side, but which one are you the most comfortable about or where do you see the greatest – where are you the most different to the consensus of you in terms of your sustainability or your APEX rigs or you're kind of – or what you see on the pressure pumping side? Some of that goes a little bit also around what you see on spudding versus a completion and a duck trend that is building up at the moment?

Interestingly enough, Ole, I'm kind of optimistic on both sides, frankly.

I asked which one? Come on.

Let me try to give you the reason why. On the rig side, drilling side, I don't think there's all that many of the very high quality performance rigs that are going to be required especially when you start to differentiate 1,500 horsepower rigs with all the bells and whistles that are going to be required. So, the first point is, I think that market, if we go back to Marshall's question about if the – if rig count doubles, it's not so easy to get that many good quality, high-quality rigs. We think we're really well-positioned on that and, plus, we have the term contract covered that we've discussed in our prepared remarks. So, that's the reason on that side. On the pressure pumping side, I know a number of the people on this call have written about the attritions going on in the business and the financially weaker players who are going to be unable to continue to operate at fundamentally unsustainable prices. And so, we think with our disciplined approach, we'll be survivors and be in strong position to capitalize on a market that will return. Andy, do you want to...

Yeah. I'll just add to what Mark said. We think we're good at both of these business. So, it's tough to chose between one or the other. But the way the markets are today, it's difficult and challenging in both. However, if you look at, let's say, drilling, if there's an eventual market recovery at some point, which we do believe there will be, we just don't know when, and you look at the specification on drilling rigs that are going to be required by the market, we see that is 1,500 horsepower pad capable of 7,500 PSI and maybe a number of those are three pumps instead of two pumps. When you get in to those kind of specifications on the rigs, the number of rigs that are available as a percentage of the total rig on the sideline is much smaller and that could drive pricing up sooner in drilling. Pressure pumping, we think we're good at this business as well. We think that we're showing good operating statistics with customers that we worked for and we think we'll continue to produce good margin in that business as well but there's many more players. Pricing may not come back quite as quick in pressure pumping, but it also could depend on the labor market, and that labor market tightening could drive pricing in pressure pumping as well.

So, is it – just a little clarification on the rigs side. Are there any rigs owned by yourself or either your competitors of that quality that you have highlight that are idle today?

Yes. We have those idle today.

Okay. So, there is some absorption there. And on the pressure pumping side or the rigs side for that matter, when it comes to consolidation clearly, how do you think about the challenge of debt that in many cases is trading at $0.10, $0.20, $0.30 on a $1 and the change of control clauses that would require full refinancing of debt. Is it possible to do something? Or this company is just going to be zombies?

Ole, I think that anybody who is trying to go through that has to go through it on a one-by-one, case-by-case basis, because it depends on what the lender has in it, who the lender is, and what they're willing to do. And fundamentally, giving sort of a long overview of that is hard to do. My experience in the 1980s at prior companies in the oil patch was that depended on each particular case. We actually think that our management team is well situated based on its experience and our balance sheet to potentially take advantage of those circumstances if they do arise. But trying to figure out which one until you – and predict it to you folks is almost impossible.

Okay. Thank you very much.

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

Yes. Good morning.

Morning, Scott.

Andy, you did highlight that you have options to eliminate the covenant on the 2015 term loan that may restrict cash distributions. Can you just speak a little bit further about your appetite to sustain the dividend in the current environment? We're just getting a lot of questions from investors on that point. And specifically whether you would utilize the revolver to pay off the loan, even before the underlying market improves?

Just speaking in terms of the dividend at a high level, this is something that we evaluate on a quarterly basis. And of course in a market like we have today, the discussions are maybe more pronounced. But it's an ongoing evaluation on a quarterly basis. Mark, would like to add anything to that?

Scott. I guess I'd said I'm happy for you to recognize that – and we put it in the prepared remarks just so that we could perhaps allay the investor concerns about the covenant. That there was financial flexibility with respect to how to handle that covenant if we decide to – we want to do so. The second point I would make is that the covenant doesn't really go to the question of is the company financially strong? And with our cash position, our undrawn revolver, our cash flow, et cetera, the company's fundamental strength is there. And so the question is not whether we can pay the dividend, it's whether that's the best use of our resources. And that's a decision that we make every quarter along with the question of should we buy back stock and then various other kinds of questions. And that's one which I think we have shown a long-term history of I think pretty much getting it right. Not to pat ourselves on the back, but I think we've done a pretty good job of being stewards of capital and buying back stock and making dividend payments, et cetera, over the long haul for the benefit of the shareholders. And so when I see the question asked, I think sometimes we are getting grouped with the people who are unable to pay those dividends, because of their financial position, as compared to the people who might make a decision as to what the right thing to do is. I want to make sure that distinction is very carefully drawn.

No, you're clearly in a stronger position. I guess just to hit the point home a little bit further though, would you be willing to reduce your liquidity near term for a few quarters to sustain the dividend?

Scott, I think that that question I would have to ask you five more before – and you'd have to give me five more assumptions for something like that before I could answer that question, because it depends on what you see as opportunities in the marketplace. I mean you're paying a dividend in order to reward the shareholders based on the profits of the company over the long term. That's the basis of a dividend. But you're also saying to yourself, what do I think will do – benefit the shareholders the most over the long term? That's I think the correct way to see it. And that's a decision about allocating capital. And you would have to tell me what the price of oil is, the price of natural gas, the number of rigs running, the amount of pressure pumping activity, margins, and then a few more things. And then I could give you the answer about the liquidity. I mean liquidity is not the be-all, end-all. It's what's good for the company.

No, I think that's very fair. And I have no doubt you guys will be thoughtful and strategic about it. A follow-up on average dayrate for rigs under contract. Where does that stand today?

We haven't called out the average dayrate for rigs under contract, only the average revenue per day.

Has the number though been changing based upon the mix of contracts in place? Or any efforts by customers to maybe utilize blend and extend to reduce their rig expenditures? Is that number moving?

In general as you look across 2016, as the number of term contracts reduce, you've got – because of the timing of when they were signed, the average revenue per day for those rigs under term contract is actually going to go up. But you also have to take into account rigs that may be on standby, which is allowed through the contract. So we continue to work within the framework of the contract, but you've got a blend of the standby in there as well.

Got it. Thanks for the color.

Thanks.

And our next question comes from John Daniel of Simmons & Company. Your line is open.

Thank you. First, I guess I'd like to touch on the – just the whole attrition debate. Andy, as I'm sure you know there are varying estimates out there regarding frac fleet attrition. Some have called for 4 million to 6 million of horsepower this year. Last week on its earnings call RPC seemed to agree with that estimate, but it doesn't expect any attrition within its own fleet. First, do you agree with the fleet attrition thesis of 4 million to 6 million horsepower? And just if so can you also comment on how much horsepower you guys might retire this year?

So first off when it comes to attrition, we could really only speak about our own fleet. And we don't expect any real attrition out of our own fleet. We stacked 140,000 horsepower at the beginning of this year, and we stacked horsepower last year. But this was all horsepower that can be maintained, can be brought back to work. When it comes to attrition in the industry, I don't think we have the best view. We work in two regions. We're working in Texas in the Permian. We're working in the Northeast. With the road trips you make you've probably got a better overall view of this than we do. So I certainly could concur with your numbers and the estimates that you come up with. But it's harder for us to get a view of it.

Yeah. Fair enough. Okay. Can you just walk us through – or just explain how complicated, expensive it is to add that third pump and make a rig 7,500-psi capable and just what percent of your fleet have that attribute?

So, in terms of – let's talk about the 7,500 psi first. All the rigs we built last year have the piping for 7,500 psi. Around half the rigs we built the year before had the piping for 7,500 psi, so it just becomes an addition of the fluid end. If a rig doesn't have the piping, it's a matter of a couple weeks to install that piping. So, it's certainly all upgradable but we have a number in the fleet. If you look at our spec sheets online, it may not always call out the 7,500-psi piping if the 7,500-psi fluid ends aren't on the pumps. So, it's not always visible on our spec sheets online. But we do have a number of those rigs, and it doesn't take us long to upgrade one in the basin if it doesn't have it. In terms of the third pump, it's a matter of plumbing. It's a matter of electrical control systems in the drive base. And we have a number of rigs that can be upgraded to that third pump.

Okay. Fair enough. And then the last one for me, just on the – given where the CapEx budget is for this year, it looks like depreciation, your guidance is flat quarter-over-quarter. John, at what point do we start to see it roll off given the lower CapEx spend?

We expect it to begin declining sometime this year. Still a little unclear as to what quarter we will see that in.

Okay. Thank you.

And our next question comes from Kurt Hallead of RBC.

Hey, good morning.

Hi, Kurt.

Hi, Kurt.

Hey. Great summary, great summary so far. I'm kind of curious you made comments very early on about the stacking of frac horsepower kind of to date. And you may have mentioned something about attrition industry-wide but I might have missed that. What do you expect – do you think we're at the absolute trough with respect to the need to stack frac equipment at this juncture?

So just to kind of recap where we are on stacking equipment, at the end of the third quarter, we had around 38% of our equipment stacked. We didn't stack any in the fourth quarter just because our activity levels remained better than we expected. But since the beginning of the year, along with commodity prices and slowing of activities, we just saw deteriorating market, and we decided to stack another 140,000 horsepower. Our choice to stack the equipment is not about us losing work. What we see is we're trying to protect our assets. We don't want to see any unnecessary attrition in our own asset. We can continue to maintain them. When activity levels come back, if you need to bring this equipment back off the sidelines again. In terms of industry attrition, because of the regions we work in, it's hard for us to have a view across the U.S. really what attrition looks like in other companies. So, I just don't think we're in a good place to talk about industry attrition. I think others do more work than we do in terms of that. But we're just trying to protect our own assets and be disciplined about how we're using our own assets and stay margin-focused as best we can.

Great. I got...

In terms of are we going to see further stacking. I think it just really depends on the market right now.

Okay. Great. And then there's perspective in the marketplace that the frac services market is going to tighten well before the land drilling market will tighten when the ultimate recovery does occur. Do you guys share that view?

I think there's several variables there. I think people are looking at the drilled and uncompleted wells that are out and therefore some of those could come back but not everybody has ducks in all the regions. Then there's attrition on the equipment, and I think that continues to get more pervasive in the industry because of the negative cash flows that a lot of companies are operating at and they're just not necessarily maintaining their equipment. And so, I think attrition is likely speeding up in the industry, but we just don't have a good view of how much. It is very difficult for us to quantify that. And then, in an eventual recovery, I think the labor market is going to be a bit challenging, and I think you're going to see a tightening there. So, that's how I see it playing out.

Appreciate it. Thanks.

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

Hey. Good morning.

Good morning, Chase.

Hey. Good morning, Andy. Good morning, Mark. So, I guess, the first question, I know you guys have done a fabulous job with the design and the technology of your APEX rigs, especially kind of the APEX-XK. But how do you see Schlumberger's acquisition of CAM and the likely entrance into the land rig market playing out over the medium to long-term.

I think we have to go on our own track record. The APEX rigs have done very well. In overall utilization over the years, the APEX-XK is a very high performing rig in the basins that it works in and we just have a solid track record when it comes to our own operations and we'll remain very competitive.

Okay. All right. And a quick question on the OpEx per day came in at $12,400 and just trying to adjust some things for standby rigs and so – did you say that you had 12 standby rigs in the fourth quarter, is that right?

Yes.

Yes. That's correct.

And are the – is the cash OpEx on these standby rigs effectively zero?

Pretty close to it.

Okay. So if I do that calculation, I am getting a little – something a little over $14,000 a day. So as we kind of move forward and these standby rigs start working, is that something we should be modeling as we kind of get into 2016?

It's hard to say in the market today if I'm going to be able to put standby rigs back to work, so it's – there's still a lot of moving parts in there in the overall numbers between rigs on standby, rigs on term contract, rigs that are working at market rates, there's just a – there's a mix.

Chase, I think that's fundamentally a call on what you think the timing is of the recovery.

Okay. But do you think these rigs stay on – under current market conditions, these stay on standby through 2016?

Some of the standby rigs are under term contracts, which could be finishing up, too. So some rigs could be coming off standby because the term contracts are ending.

Okay. All right. I guess, kind of follow-up on that real quick. Could you talk about where you think your term contract coverage will be at the end of this year? You've given us the average for the year, but maybe if you will give us an exit number.

Today, we're just giving you the average for the year.

Okay. I will try one more. So what about the average term dayrate for the 46 rigs under term contract this year?

We just haven't called that out. We give you what the average rig revenue per day is, the cost per day and margins, of course, but we just haven't called out what the average term contract rate is. But what I have...

Would...

There's a progression in 2016 where the term contract rates go up because of the timing of when those rigs were signed.

Okay. So it goes higher from here throughout the year?

Except for rigs that could be on standby.

Got it. Got it. Okay. That's helpful. All right. Thank you.

And our next question comes from Robin Shoemaker. Your line is open.

Yes. Good morning, Andy. I wanted to ask you, of the companies that have reported so far, the public companies, basically everyone says that they prefer to stack their pressure pumping equipment and not wear out their equipment for no margin and that's the policy. And, of course, you add all those companies up, they account for the vast majority of pressure pumping equipment in the U.S. So that leaves the others. And I just wondered – is there any – do you think there is anything there regarding either those that are in the lowest – working for the lowest rates, that they have some kind of lower wage rates or lower some other costs at G&A or other that actually gives them some kind of advantage?

No. I don't see that there's any real advantage, especially with some of the smaller companies. I think they're trying to survive. And one scenario that's potentially playing out right now is you have companies who are working at negative cash flow because they're still going through bank evaluations and working with bankers. And if that equipment is not working, then the asset value goes to near zero. But if the equipment is working, even though they're at negative cash flow, they get more valuation on the asset. And so I think this is that part of the cycle where you have companies that are just fighting to survive in that respect as well.

Yeah. I can appreciate that. That makes sense. Just – on your comment on the labor market, I mean, it certainly – with all the people who have lost their employment in the last year, it certainly would seem to be a very large pool of people out there for – who may have found alternate employment, but probably would come back because the compensation is higher. But are you referring to a labor market that tightens in the first year of a recovering market? Or more like the second or third? If you put back 200,000 or 300,000 horsepower to work or 30 APEX rigs, would you already feel it then?

I believe you would feel the labor market tightening up within the first year. I think it's hard to know, but it's going to be in that first year or less because I think a number of employees that unfortunately we've had to release have found work elsewhere. We recruit nationally. We have people that rotate across the country and in their hometowns, which aren't necessarily West Texas or places where the rigs work. They found other employment in some cases because there is a labor market around us.

Yeah. Okay. Interesting. Appreciate it, Andy.

Thanks.

And our next question comes from Sean Meakim. Your line is open.

Hey. Good morning.

Good morning.

So I wanted to drill a little bit on dayrates and the recovery. In some of your comments earlier, it sounded like you were – your view is that pad optimal rigs are a more discreet market that can get pricing in a recovery faster than perhaps into the rest of the AC or horizontal market. Is that your assessment? Or do you think we need higher utilization across the kind of broader horizontal fleet to get improvements in pricing for each of the subsets within the AC fleet?

So, first off, pricing dayrates is still very competitive. It's going to remain very competitive in 2016 because of where activity is. But in the scenario when we do start to get a recovery, the rigs that are going to go back to work first are going to be the 1,500 horsepower, with the walking systems, 7,500 PSI circulating systems, maybe three pumps on the rig, 750 tips mass (46:29) load. So it's those kind of specifications that we think the customers are going to want first. And those are going to go back to work first. I don't think you get immediate pricing power with a rig like that just because utilization is low in the market and we all have rigs like that that are stacked on the sideline. But I do think you get some pricing power relatively quick after that, maybe relative to other segments, even relative to pressure pumping. In pressure pumping, I think it's going to take a little bit more to get the pricing back up in that market. There's a number of competitors out there.

So we don't necessarily need 80% utilization across, say, all AC rigs in order to get pricing power within that subset of pad optimal rigs?

No, not at all. In fact, when you look at the fleet of AC rigs that are stacked on the sidelines today, if you start to dissect that fleet, you see a number of less capable rigs, whether they're 1,000 horsepower, whether they're super singles. They're not pad capable so you have to break those out of the fleet that's stacked on the sideline.

Okay. Yeah, thank you. And then, I guess, to switch over to the bifurcation that you mentioned between competitors, and just thinking about the potential for asset sales, we saw a pretty strong bid for pumping assets recently. And so I was just curious how you think about competition from private capital that's on the sidelines, and in terms of potential consolidation as we get through the down cycle and into a recovery?

Any consolidation in pressure pumping is positive for that sector of the business. Whether it's somebody else doing the consolidating or ourselves doing the consolidating, any consolidating is a plus. There's too many companies in pressure pumping, and the pricing is unsustainable.

Sean, I just have one additional thought, which is that over the past say 10 years, we saw a lot of new money come in to build assets in that marketplace. What I think this downturn has caused is that there's not money going into building new assets. And so what we're going to see is a decrease in the amount of available assets, not an increase, probably consolidated among fewer holders. And that the likely in effect buyers are going to be people who already have investments, who are making investments that they see as strategic.

Yeah. And that's what we're seeing here too. Yeah. Thank you very much.

And our next question comes from Marc Bianchi. Your line is open.

Hey, guys. I just wanted to ask first on the standby rigs. It looks like – I think you said that there were two more standby rigs in the fourth quarter. And that affects – doesn't affect margin, but it does affect dayrate. If we were to normalize for that, what would have been the sequential day rate change? Just trying to remove the impact of the standby rigs.

Yeah. There's so many moving parts. I don't have that number in front of me. It's more than just the standby there.

Okay. Okay. Would it have been up sequentially if it were unchanged?

We just don't have that with us right now.

Okay. And the other question is as it relates to the rigs on contract, it looks like the average for 2016 went up by one. But you talked about some early termination in the fourth quarter and some expectation for early termination here in the first quarter. So can you help reconcile that? Did you put some rigs – new rigs onto contract? Or take some rigs off the sidelines and put them on contract?

So we did. In the fourth quarter we did sign a couple of term contracts, very short term, and at what we considered reasonable market rate. We're still margin-focused. But we did sign a couple of very short-term contracts.

Is there any – can you talk to the types of rigs and what the work was? Are they these 1,500 upgraded rigs that are replacing something that was of lesser quality? Or any other color you can provide on that?

They were APEX rigs, because that's pretty much all we're working right now. And of course being an APEX rig, they are of very good quality. They had good performance metrics in the basins that they were working in previously, which is why we were able to get the – keep the rigs working. And the short-term contract that we signed gave us a commitment on the rig. So it was mutually beneficial for both parties.

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

And our next question comes from Waqar Syed. Your line is open.

Andy, I have a question on ability to – or intent to provide additional services from a rig. Some of your competitors are looking to provide additional services to maybe generate more revenues per rig, like casing and tubing services or any other additional services. Is that something that you would look into?

Waqar, today we're just very focused on the businesses we're in, in drilling and pressure pumping and just trying to maintain the margins that we have. I think we said before we're open to looking at opportunities to do other things, whether it could be organic, it could be through acquisition. We're going to look at opportunities. But this has been a pretty challenging downturn. And we've had to really stay focused on what we do best right now.

Okay. And then on something that you have discussed in the call as well, but I just wanted to maybe dig deeper. What do you think would be the reactivation costs if you have to reactivate your drilling rigs past maybe the first 30 or 40? And then again on the pressure pumping side, what do you think the reactivation costs would be if you have to bring back equipment? Both on the equipment side – and perhaps you addressed some of the wage issues, but on the equipment side.

So in a reactivation scenario, which we're hopeful that eventually we'll get to, but we're not there yet. We're going to have costs associated with labor. In drilling it could be two weeks to four weeks of labor costs, as we get the rig back out. In pressure pumping I'm anticipating maybe a month of crewed labor to get the equipment back out. And therefore because of that, the cost – or the pricing to get the equipment kind of back out is higher than equipment that's already working. So when we talk about reactivation equipment, we're talking about equipment that we expect to go out at a higher price than maybe equipment is working today.

Okay. But in terms of the rigs that – if the rig has been stacked for about a year or so, and then you have to reactivate that, is there any cost associated with actually moving the equipment, in terms of finding spare parts, or just painting it, or running the engines, or things like that? Is there any costs involved there?

You have the transportation to mobilize it out. But outside of that we don't expect any major expenditures to mobilize a rig or even the pressure pumping equipment.

Okay. Great. Thank you very much.

And the next question comes from Darren Gacicia. Your line is open, Darren.

Hey. Thank you for squeezing me in. I appreciate it. When I put out my initiation a couple months ago, I had the 1,500 AC fleet at a little over 800 rigs. I'm kind of curious what you think about that number? Whether it's a little low or a little high? And then a little bit of a sense of – if your crossover point on pricing is probably 80% utilization and looking higher, what does that have to be from a rig count standpoint to maybe just start to see pricing coming back if the first entrants back are basically only kind of trafficking those rigs?

So let's start with the first part. The number of 1,500 horsepower rigs that are stacked on the sideline is probably less than 800. I don't have that in front of me right now, but that seems a little bit high. The other thing...

Well I'm just talking like the total fleet, not the stacked number.

The total fleet. It just seems a little bit high. But also what I want to get to is in the 1,500 horsepower rig category, what you don't see in a lot of the macro data that circulates is not all these 1,500 horsepower rigs have the 750,000-pound graded mast. And so there are some older rigs that are mixed in with that that might have a lighter mast that are just going to be less marketable when we get to an eventual recovery and when people are looking at rigs. So you really got to kind of dissect what that rig fleet looks like more than just the horsepower.

So, is that – I mean, so if you look at it and kind of the adjustments you're saying, is it off by an order of magnitude of 50 rigs, 100 rigs, 200 rigs? I mean, what's – just to kind of get me order of magnitude to think about that comment.

Yeah. So Mike just pulled the number, and we believe there's approximately 700 1,500 horsepower AC rigs total in the industry. And then – I don't have the number of – it breaks down into what I've described before, but it's probably in the 200 to 300 range, but I don't know for sure offhand. But the other part of your question was really about pricing and utilization. What we've seen historically is there was pricing power in high-spec drilling rigs below 80% utilization. We saw that in 2013 and 2014.

Got you. So when you look at your fleet, I know that there is a ton of cold stack, there could be warm stack, and then there's sort of – what's the amount – given the fact that you probably have to train new people and do some work on the rigs to bring that out, what would be the pace at which you could probably bring single rigs back on? Can you elaborate a little bit on the process that has to happen there?

Well, we will have to bring people back if we're reactivating rigs. The way that we structured how we're operating today is we've kept as much of the experience as we can in key leadership positions. So when we do bring people back, we're talking about bringing back the entry-level people, more the floor-hands. And so the training time to get people back is not as much as maybe people think. So I think we can put it out and we can reactivate rigs within two to four weeks.

Also the fact is that during this downturn, what's happened is people take lesser positions and go from one position on the rig to a lower position on the rig. And that person can be promoted back up as we bring in the less-skilled people. So the way we've done it sets us up to go the opposite direction as well.

So if there's any one parabolic on you, just hypothetically speaking, like how many rigs do you bring on the floor, do you think? And do you really want to put the pedal to the metal?

I think that no one can give you that bit of information because you'll have to tell us what the demand is, what the pricing is, and so on and so forth because all those factors will be implied.

Got you. I was just sort of thinking from a really far extreme example, if you really wanted to bring everything you possibly could back on. And everything was pricing to the extent that allowed you to do it, et cetera.

In general, there's no limit to how many rigs we can put back to work that are stacked on the sidelines. The equipment is in good condition. It's just a matter of putting the labor force back in place, but that labor force is going to tighten up. And so, it's really the labor issue more than just the equipment issue. But that's all very market dependent as to how many rigs we would put back and how fast that will happen.

Great. This is super helpful. I appreciate it.

And our next question is coming from Brad Handler of Jefferies. Your line is open.

Thanks. Good morning, guys.

Good morning, Brad.

A lot of good questions and a lot of optimistic questions, and I appreciate that. Mine is a little less, so, I guess, forgive me. But I guess, nearer term, I'm trying to understand a couple of things better in terms of what you can see. So, I think if we look at your rig count outlook for Q1, if we're doing sort of math right based on the visibility you give us through the course of the quarter, it looks like you're sort of expecting to exit the quarter at around 60 working rigs in the U.S. so that...

That'd be close. That's not too far off.

Okay. So, basically, there'd be a handful of rigs working in the spot market relative to a contract roll-off if they kind of proceed the pace?

Correct.

Okay. And is that a pretty good measure? I mean, how much – I know this is sort of an obvious question, but is there opportunities perhaps to – for that to be higher in some ways? Are you seeing – is there a quoting activity that might allow that to actually – the spot market to be a little bit larger at quarter end or just...

That really turns on your macro call, Brad.

Yeah. Fair enough. But it's so short – I mean, we're talking about a month or two or three, a month or two away. So, it feels like a little less of a call and more what operators are doing right now if you could find the line up somewhere.

Q1, it's safe to say because our commodity prices got off to a very difficult start and that's why we're projecting that the average rig count is going to go to 70 in the U.S. and your number for an exit is probably not too far off. But I wouldn't say we have visibility on what I would call opportunities right now. It's still a difficult market.

Right. I appreciate that. I know it sounds a little – probably, it sounds a little silly to ask it that way. But how much – maybe you can help us understand, if something has gotten early terminated or turned on standby, can you generalize how much visibility you had before that happens? Is it a long conversation with you back and forth? Does it tend to be sneak up on you and you – how have they worked?

It's in the range of weeks to 30 days. We just – it's certainly not within – it's not – we don't get a quarter's notice on some of these things right now.

Yeah.

Our customers are reacting to commodity prices. They pick up the phone. They call us. We have a discussion. But some of these things are happening relatively quick.

Right. Right. Yeah. It certainly – that makes sense. Okay. Okay. Very good. Well I know it's running late, so thank you. I'll turn it back.

Thanks.

And our next question comes from Mark Brown. Your line is open.

Hey. I know it's running late. I will – wanted to see if you had any comments on the supply chain management efforts that you've run so efficiently and you talked about PROPLOGIC sand management and such in the past. Any trends in terms of sand costs, sand hauling, chemical costs that you can point to in Q4 or early 2016?

In 2015, I gave a lot of credit to our operations working with our supply chain teams and then working with our suppliers to get our costs down which in terms – especially in terms of products, like sand and chemicals, gets the costs down for our customers. But in 2016, I'm not sure how much more we can get out of the supply chain, whether it's from the mines, whether it's from the chemical suppliers. We worked hard in 2015 to take cost out of the system. It's getting more challenging in 2016 to take cost out of the system.

Understood. And then finally just curious on Canada, only three rigs over the quarter, very small scale. Just curious, is that a region where you think the recovery is going to be lagged relative to the U.S. and does it make sense to maintain a presence there?

So, we've been in Canada for a while. We successfully put a new APEX rig up there under a term contract and very pleased with the performance of that rig. So, we anticipate that, long term, we'll be successful in Canada, but Canada is in a very difficult situation as an industry right now. And their market reacts a little bit different from the U.S. market both in terms of magnitude and timing just because their takeaways move in different directions, whether it's natural gas or oil in Canada.

All right. Thank you very much.

Our last question comes from Jason Wangler. Your line is open, Jason. Jason, if your line is on mute, please un-mute your line.

Yeah. Sorry about that. I just had one quick one. Just you did a great job of walking through a lot of the stuff. Just curious more specifically in the first quarter as you've had those conversations about the standbys, how those have gone with the drop in oil prices and obviously activity coming down? Have you seen a lot more of the standby contracts come up?

I wouldn't say it's been a big change. It only increased from 10 to 12 in the fourth quarter, and then we're likely to see some of those roll off in 2016, but I wouldn't say it's a big shift.

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

Thanks.

And I'm showing no further questions. I'd now like to turn the call back over to management for closing remarks.

I'd just like to thank everybody for their participation and look forward to speaking to them after the end of the first quarter. Thank you, everybody.

Ladies and gentlemen, that concludes today's conference. Thank you for your participation and have a wonderful day.