Patterson-UTI Energy, Inc. (PTEN) Q1 2016 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Patterson-UTI Energy Incorporated First Quarter 2016 Earnings 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. [Operator Instructions] As a reminder, this conference is being recorded. I would now like to introduce your host for today's conference, Mr. Mike Drickamer. Sir, you may begin.

Thank you, Antuan. 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 months ended March 31, 2016. Participating in today's call will be Mark Siegel, Chairman; Andy Hendricks, Chief Executive Officer; and John Vollmer, Chief Financial Officer. 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 form on report – 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 first quarter 2016. We are pleased that you are able to join us today. As is customary, I will start by briefly reviewing the financial results for the quarter ended March 31st 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 first quarter, as set forth in our earnings press release issued this morning, we reported a net loss of $70.5 million, or $0.48 per share, on revenues of $269 million. Depreciation and amortization expense during the first quarter was $177 million. Total adjusted EBITDA during the first quarter was $81.5 million and we remain EBITDA positive in all three of our business lines. Our financial position remains strong and we will remain prudent with our capital spending. Our cash balance increased during the quarter by more than $73 million to $187 million at March 31st. Additionally, our revolving line of credit remains fully available. To further improve our liquidity position, in advance of the opportunities arising from a cyclical recovery, we have elected to reduce our quarterly dividend to $0.02 per share, which should save the company approximately $47 million on an annual basis. With that, I’ll now turn the call over to Andy.

Thanks, Mark. In contract drilling, our rig count during the first quarter averaged 71 rigs in the U.S. and three rigs in Canada, compared to 88 rigs in the U.S. and 3 rigs in Canada during the fourth quarter. During the first quarter, total contact drilling revenues were $169 million, including $16.8 million of revenues from early contract terminations. These early contract terminations positively impacted our average rig revenue per day of $25,340 by $2,520. Excluding early termination revenues, average rig revenue per day during the first quarter would have been $22,820, which is down $320 from the fourth quarter. Total average rig operating cost per day decreased $490 during the first quarter to $12,150. This decrease is due in part to a reduction in our workers' compensation reserves, resulting from our strong and consistent operational record. Additionally, the proportion of rigs on standby increased during the corner as we had an average of 13 rigs on standby in the first quarter. As a reminder, rigs on standby have very little associated cost, thereby reducing the overall average rig operating cost per day. Total average rig margin per day during the first quarter was $13,180. Excluding the positive impact from early termination revenues, total average rig margin per day increased $160 during the first quarter to $10,660 from $10,500 during the fourth quarter. At March 31, we had term contracts for drilling rigs providing for approximately $580 million of future day-rate drilling revenue. Based on contracts currently in place, we expect an average of 43 rigs operating under term contracts during the second quarter, and an average of 40 rigs operating under term contracts during the remaining three quarters of 2016. Looking forward, assuming crude oil prices remain near current levels, we believe rig counts will stabilize. Visibility into our own rig count suggests that our April rig count will average 56 rigs in the U.S. and the second quarter rig count will average 54 rigs in the U.S. In Canada, due in part to the downturn and spring breakup, we expect a minimal number of operating days in Canada during the second quarter. Average rig margin per day excluding early termination revenues is expected to decrease to approximately $9,350 per day in the second quarter. The expected decrease is primarily attributable to a decrease in average revenue per day as rigs roll from long-term contracts to negotiated rates. In addition, early termination revenues in the second quarter are expected to be approximately $5 million. Turning now to pressure pumping. Pressure pumping revenues during the first quarter were $96.3 million, compared to $132 million in the fourth quarter. Gross margin as a percentage of revenues decreased during the first quarter to 8.8% from 10.4% in the fourth quarter. We continue to generate positive adjusted EBITDA for pressure pumping, which totaled $5.6 million during the first quarter, compared to $10.9 million during the fourth quarter. We believe it is prudent to be disciplined in the use of our assets, and our strong balance sheet allows us to be selective in accepting work rather than chasing work that pricing levels that do not generate acceptable cash flow. Our focus continues to be on margins rather than market share, and so we are stacking equipment rather than having the equipment incur the wear and tear while generating unacceptable cash flow. We now have approximately 54% of our more than one million frac horse power stacked. One of the big discussions pertaining to the pressure pumping industry is that of attrition. Everybody seems to expect there will be attrition in the industry, but many believe it will be somebody else's equipment that gets retired. We believe that there is a natural industry attrition of around 10% of the working pressure pumping equipment each year. We also concur with others that in 2015 and 2016, this percentage could be at least 20% each year for the industry due to a combination of no equipment additions or replacements, retirement of older equipment, and companies with weak balance sheets maintaining their utilization through cannibalization of stacked equipment. In the case of Patterson-UTI, we continue to fund pressure pumping, OpEx, and CapEx for maintenance of our own working equipment. And we do not expect any unusual attrition of our own fleet, which is an average age of 4 years. We expect that substantially all of our stacked horsepower is capable of going back to work in a market recovery. For the second quarter, we expect activity levels will decline further, leading to an almost 20% sequential decline in pressure pumping revenues. With a lower activity level in the second quarter, gross margin is expected to decline at 6%. In both of our core businesses, drilling and pressure pumping, we undertook a careful process to stack equipment during the downturn, thereby leaving us well-positioned to reactivate equipment during a recovery. We expect that across the industry, the biggest challenge to reactivating equipment will be associated with recruiting, hiring, and training new employees. While labor may initially be easy to find, given the magnitude of the workforce reduction in the industry, we expect it will be very challenging for the industry to meaningfully increase the number of personnel quickly, given the magnitude and duration of the downturn. Before I turn the call back to Mark for his concluding remarks, let me provide an update on several other financial matters. In general, in both drilling and pressure pumping, we remain very focused on reducing costs and protecting our balance sheet. With respect to our capital spending, we'll be pragmatic, recognizing the importance of cash, but also acknowledging that our balance sheet strength affords us the opportunity to maintain, and when appropriate, make upgrades to our equipment, thereby better positioning us to react when conditions improve. While we have a total CapEx budget for 2016 of $190 million, we now expect to spend approximately $170 million. Given the slowing of our capital spending in 2015 and 2016, we expect depreciation expense, excluding E&P impairments, will decrease approximately $4 million per quarter for the remaining three quarters of 2016. For the second quarter, depreciation expense, excluding E&P impairment charges, if any, is expected to be $171 million. SG&A during the second quarter is expected to be $18 million. We are currently projecting our effective tax rate to be approximately 36% in the second quarter. Without a significant recovery in market conditions, we do not expect to pay meaningful cash taxes during 2016. We received a tax in the first quarter of $19 million, and we expect to receive another refund of approximately $25 million later in the year. With that, I will now turn the call back to Mark for his concluding remarks.

Thanks, Andy. As Andy mentioned, we believe the U.S. rig count is beginning to stabilize, driven by the improvement in crude oil prices from cyclical lows reached earlier this year. Accordingly, our rig count is also expected to begin to stabilize. Furthermore, we believe the stabilization of drilling activity will also allow for pressure pumping activity to stabilize. However, we believe the current commodity prices are not sufficient to support a meaningful increase in U.S. drilling and completion activity. The outlook for crude oil prices remains uncertain, with numerous economic and geopolitical risks and opportunities. Therefore, visibility into the timing and magnitude of a recovery remains limited. While activity levels are beginning to stabilize, and we see this as an improvement, industry conditions with nonetheless likely remain challenging during 2016, due to the current weak utilization and pricing levels. Under these conditions, we will remain focused on operational execution and preserving our balance sheet, which will help us whether this downturn and succeed during the next recovery. With that, I'd like to both commend and thank the hardworking men and women who make up this company. I and the management team appreciate your efforts during this challenging market environment. Operator, we'd like to now open the call for questions. Antuan?

Thank you. [Operator Instructions] Our first question comes from Sean Meakim from JP Morgan. Your line is open.

Hi, good morning.

Good morning.

So, you guys are getting in-bounds from customers likely on both the drilling side and the pumping side as we think about the second half of the year. I was just curious if you could maybe give us a little bit of comparison to what we saw last year, and was ultimately kind of a fleeting rally? And just it would be great to hear your thoughts of what the compare and contrasting last year versus this year, in terms of how those conversations are going.

I think in terms of last year, if you're referring to the June timeframe when crude was trading in the 60 or 62 level versus where we are today, it's not quite the same. What we see today, in the visibility we currently have, is around stabilization of activity, both drilling and pressure pumping, given today's commodity prices. But we're at a record low rig count. We don't see meaningful increases in activity in today's commodity price either. And so the stabilization for us right now is a positive after almost a year and a half of rig count decline. But we're still in a tough environment.

I think that's very fair. So then, as you think about when recovery does get underway at some point, how are you thinking about – traditionally we'd see drilling activity lead completions activity, but it seems like a lot of speculation that we would see perhaps more of a recovery coinciding in pumping coinciding with drilling – just get your thoughts there as well.

Well, I guess I'll frame it up by referencing your first question and what happened back in 2016 – or 2015, sorry, in June. You know, when oil prices were trading at the $60 or $62 level, we were getting phone calls both in our drilling business and in our pressure pumping business. And it'll just be interesting to see how this plays out, but it could be very similar. But again, we're just not at a commodity level that drives those types of phone calls yet.

Got it. Okay. Thanks, Andy.

Our next question comes from Marshall Adkins of Raymond James. You may proceed.

Morning, guys. I find it a little odd saying that you all did a great job with the quarter when we're still losing $70 million, but you did do a remarkable job on the cost side. And that's my first question, is, how – where did the cost reductions come from? Is it reduced labor force, or is it coming from vendors, or – help me understand how you all are able to do a better than average job on the cost side.

Hey, good morning, Marshall. I think the best way to answer that question is to tell you it comes from various fronts. It's not any one single thing. Certainly with the decrease in activity, we continue to scale the business so that we're the appropriate-sized company for the activity that we have in general. Especially when you look at drilling, we're still paying the same wages that we were paying for the positions. Unfortunately, many of our people – in fact, most of our people at this point have had to take lower positions on the rigs. But that base daily wage cost at the rig level is still roughly the same. We have continued to negotiate with suppliers. I wouldn't say that we're getting a huge decrementals in that in terms of reductions in our cost, but we still see a little bit of reduction through some negotiation with suppliers, improvements in logistics and some areas in that respects. So we continue to attack it on several fronts. It's a tough environment. The rig count is very low right now, and we're doing what we can to try to keep our costs in line.

Okay. Switching gears. Apparently you've got about a million horsepower pressure pumping, and there's a lot of, as you mentioned, speculation on attrition and whatnot. Am I reading you correctly when you're saying, all your stuff go back to work? Have you had any attrition at all, or is all that million horsepower good to go without meaningful investment if we turn the go button on tomorrow.

So the little bit of attrition we've had, and I'll describe it as de minimis, a few older 1,800-horsepower pumps, but that's really about it. We expect that really all of the equipment that we have stacked can go back to work. There'll be some maintenance cost. There'll be some CapEx costs. We don't see these as unreasonable costs going forward. It's one of the reasons that we're focused on cash and liquidity and making sure that we're well-positioned for a recovery. But the average age of our fleet is 4 years old, mostly new quintuplex pumps. We feel we're in good shape for when that recovery does happen, although we don't have that visibility yet.

Just one quick follow-up on that. Where do you see, in a recovery scenario, which certainly we envision for 2017, where do you see the bottlenecks involved? You mentioned labor. Or is it going to be equipment in the industry from attrition? Or – help me get a sense from you on where you see the bottlenecks developing over the next, call it 18 months.

I believe the number one issue is labor. I think everybody's going to have the same problem we're going to have. I think it's going to be an industry challenge. I think that other companies are potentially going to have challenges with working capital, challenges with CapEx to get equipment back working again. So that could cause some tightening in the market too. But I think labor will be our biggest challenge. When you look at how far we've declined – our rig counts come down over 75% percent now for us – when you look at the people that unfortunately we've had to release, people that have left our company in the last 6 months, there's a good chance we'll get a fair number of those back. But once people have been gone from our industry for more than 6 months, and certainly in our case these are a lot of hardworking men and women, they're very likely to find work elsewhere at that point.

If we're 430 rigs to date, can we get back to 1,000 rigs a year from now?

I think that's really going to depend on the market. It's going to depend on what commodity prices are doing. And I think as an organization we have the ability to react, but labor will be the bottleneck for us.

Thanks, guys.

The next question comes from Waqar Syed from Goldman Sachs. Your line is open.

Thank you. Andy, just following on the same line of questioning, in the case that there is significant demand growth, as an organization, how many rigs can you add in a quarter? And what kind of a lead time would you need to do that?

It's not out of the question to add 20 rigs per quarter. We're reluctant to call out a number, because it depends on various factors. We could do even more than 20 rigs if we need to. When it comes to labor, we've recruited nationally in the past, and we'll recruit nationally again to bring in people into the industry and get people trained up. When you look at a drilling rig, we need to get people two to four weeks in advance of putting a drilling rig out. When you look at pressure pumping fleets, we need the crews almost a month in advance to get everything ready. So it varies by the business line. But, as I mentioned earlier, organizational – from the organizational standpoint, and the leadership and management we have in place today, we're ready for those challenges. But we will have some bottlenecks getting the labor back in place.

Now, at the current spot rates, would you be happy to add another 20 rigs?

First off, I don't really see a spot market. You know, there's not a trade where you have E&Ps out there taking multiple bids for putting up new rigs, including mobilization and all the associated costs to take a rig that's stacked. You just don't see that in today's market. We see stabilization. So it's not really a spot market. At today's pricing it's difficult to be incentivized to put a new rig out, and especially on the pressure pumping side. Pressure pumping pricing is unsustainable at this point. We're slightly EBITDA positive, but in pressure pumping, if you look at the cash and you include EBITDA, CapEx, and G&A, it's slightly negative. It's an unsustainable situation from pricing for pressure pumping.

But on the billing side, rates – we hear that rates are probably in the $15,000 to $17,000 a day range for AC rigs. First, do you concur with that? And if that's the case, you mentioned that there's very limited spot market data, but if that's the range, would you be interested in adding your rigs at that price range.

When it comes to rig rates, I think what you're hearing are more anecdotal comments. We're still going through negotiations with customers when we keep a rig running, and it's not so much of a spot rate discussion. Like I said, it's more of a negotiation. And it depends on the customer. It depends on mobilizations. It depends on the base in your end. But I think a lot of what you hear is more anecdotal, and you're going to hear different numbers from different parts of the U.S. right now.

And just my final question. You hear a lot about rig of the future that may look different, may have kind of closed information loop between bottom-hole assembly and top drives and drillers cabin, all of that. One of your competitors, [indiscernible], all working on that. How do you see that impacting the rig demand going forward? And what's the PTEN strategy with respect to that new technology offering?

So at the end of the day, rig demand is based on rig performance. Your ability to market and sell your rigs are based on your performance, your performance history. We're very proud of the operational performance that we have at Patterson-UTI, both in drilling and pressure pumping. And in drilling especially, our performance is really driving our rig count as well. It drove it back in 2014, when we were able to get as many of the rigs as we did under term contract. And so our performance metrics continue to impress many of our customers today. In terms of technology, I think yes, there’s some companies working on some interesting technology, but I'm very comfortable with the programs that we have in place and the selective technologies that we're working on to ensure that our rigs will continue to be competitive from a performance standpoint.

Is there something that you can discuss, what are those selective technologies?

I don't think we'll go into the details today, but as I said, I'm comfortable that we'll be competitive, just as we are today.

Thank you very much.

The next question comes from Marc Bianchi from Cowen and Company. Your line is open.

Hey. Good morning, guys.

Hi, Marc.

Trying to triangulate some of the guidance you gave here for second quarter in the drilling business. Is it fair to say that your contracted rigs, assuming they were done something in the low 20s, implies that your non-contracted is something in the mid-teens? Is that a fair assumption?

No. That doesn't really work out. Majority of our contracts were signed in 2013 and 2014. A lot of what you're seeing working today are rigs that were signed at the peak of 2014. We also have rigs on standby that moves those numbers as well. So it might be better to take that offline later, but no, those numbers wouldn't get you there.

Okay. Okay. Thanks, Andy. And I guess maybe one for Mark, or for whoever. But now with the dividend adjustment, sounds like maybe you guys are seeing some increased opportunity to put some capital to work. Maybe offer some more color on that if you could.

Sure, Marc. The thought here, simply put, is that we have tremendous respect for our shareholders. We have tremendous respect for the shareholders who need some kind of income component from the stock, and so we are very respectful of that. As we've said at each board meeting, we consider the dividends – and again, at this most recent Board meeting, again considered it. The thought that the Board had, which management recommended, based on management's recommendation, was that we conserve a little bit of cash here by lowering the dividend. That extra $45 million plus of cash helps us to have increased opportunities in terms of the expected recovery in the industry, both in terms of having incremental working capital, as well as since we see more and more opportunities arising in the industry. So we saw it as a benefit from a number of perspectives while at the same time being respectful to the shareholders who need a dividend.

Okay. Well, thanks for that I guess. Just in terms of beyond working capital, is there any area that looks particularly interesting to take advantage from an M&A perspective?

I guess it's fair to say, Marc, with the disruption that's gone throughout the industry, that there's opportunities across the whole spectrum. The really interesting circumstance for a company like Patterson, which has this strong balance sheet and the ability to gear ourselves to the activity levels and generate cash, we have opportunities kind of across the whole sector. For us, it's mostly an interesting question of trying to figure out what will help the company the most, and how do we take the most advantage of the circumstance, not what particular opportunity is in front of us.

Okay. We'll be eagerly awaiting. Thank you.

Our next question comes from James West from Evercore. Your line is open.

Hey. How are you? This is Alex Nuta on for James. My first question is on the drilling side, and it might be too early to be asking this, but I was curious if you guys have gotten any indication from customers with whom you have current term contracts that they would require a pricing discount on their current term contracts in order to sign an incremental rig?

We started getting that question from customers early in 2015. But a term contract is a term contract. We'll work within the boundaries of that contract, but we don't just adjust rates within a term contract.

Would you adjust rates within a term contract if it meant receiving an incremental rig?

No. That's not typically within the boundaries of a term contract on a drilling rig.

Okay. And then my second question is on the pressure pumping side. Could you quantify the reactivation costs, either on like per spread or per horsepower basis needed to be for your stacked horsepower? Between just crewing it up, making all the repairs, and so on.

It varies by the size of the frac fleet and the basin that we might be reactivating in. But total OpEx and CapEx for some of the early fleets might be in the $1 million to $2 million range. But we don't see these kind of dollars as detrimental to our ability to put equipment out in a recovery. And it's one of the reasons that we're focused on liquidity and cash right now.

Okay, thanks. And you said $170 million for CapEx?

$170 million for the CapEx plans to get right now...

For the year? Is there anything going on towards the back end of the year that it's so back-half weighted?

It's not that things are going on towards the back end. We spend dollars in terms of cash out in various quarters on various items. So it's not cash that just moves steady quarter by quarter. But total spend is anticipated to be $170 million this year.

Okay. Thank you very much.

Our next question comes from Scott Gruber from Citigroup. Your line is open.

Yes, good morning.

Hey, Scott. My only question, Andy, is for you, following up on the comment you made about attracting labor back to the industry. And after six months or so, that can become difficult. I think what's challenging in this environment, given the steep declines in rig activity, looking back even all the way back in December we were running 550 rigs according to the Baker count on the horizontal side. As we look out into the second half and assume that we start to see some rig recovery, is 550 horizontal rigs a reasonable number to start to think about, if we move past that we'll start to see some real friction in terms of attracting labor back?

It's going to be hard to say. You can just do as you say and look at what the rig count was six months ago, and we'll attract the majority of that labor back. And in the market, we'll also bring in new people to the industry from different parts of the U.S. But as I mentioned earlier, we also have the organizational capacity as a company to get the people that we need. But in terms of the various list of items that are going to make it challenging in a recovery, labor's at the top of the list.

It just strikes me that you're actually in an advantaged position, just given quality labor, quality brand, to really attract better labor, attract that labor faster than some of your peers. Are there other things that you can do to further improve your position, given what's likely to be some friction in that whole process for the industry?

Well, we certainly appreciate your comments, and we do think we're well-positioned. We do think we have a good reputation in the industry for safe and efficient operations. And we also have a good reputation in the various parts of the country that we've recruited in the past. If you remember before the downturn, half the people we are recruiting for a few years before the downturn were active returning military. And I think our reputation in those places are still good. So I think that we'll have success in getting the people, but again, that'll be the tightest area for us.

And, Scott, I would just add that we, as we had to release people, were conscious of the fact that we might very well be wanting to invite them to come back. And so we were very concerned about how we treated them as they left their employ here. And so we've thought about this a fair amount. How it works will depend on facts that are really difficult for us or anybody else to assess, because that wonderful employee that you had to let go may have found a perfectly wonderful job somewhere else, or they may not have. Hard to know that.

Well, I wish you luck during the process. Thanks.

Thanks.

The next question comes from Dan Boyd from BMO Capital Markets. Your line is open.

Hey, guys.

Hi, Dan.

Have a question on what you're seeing out there in terms of pressure pumping intensity. I think the old rule of thumb used to be one pressure pumping crew could sort of serve three to four rigs. Some E&Ps more recently, and especially those with Permian exposure, are talking closer to one pressure pumping crew for every two to two-and-a-half rigs. What are your thoughts on that?

In general it varies by basin. We don't track that kind of statistic too much. When you're running the pressure pumping business focused on completion, you're really staying close to the customer in terms of what they're anticipating, and it could even vary by customer, just because of pad layouts or other reasons. And in terms of overall intensity, I also think in terms of what we're pumping in sand volumes, in chemicals. But in terms of how many rigs are in front of us per spread, that just can vary too much.

Okay. And can you provide any color on the utilization levels you're running in the different basins on pumping between, really, the Marcellus and the Permian?

Not much to say other than, the amount of equipment that we've stacked has not changed much in the last three months. In the first quarter, we did stack a fair amount, but we have 54% stacked. Our revenues are forecasted to continue to decline, and it's really about days that become open in the calendar. So utilization is declining for the crews that are active. So if we do get some kind of increase in commodity and there is any recovery, we'll be able to fill those days in the calendar with existing crews. But it's really about utilization right now in the calendar.

Okay. And then this last one. Would you – is there chance that you increase your pumping exposure during this downturn? Or are you pretty happy with the million horsepower that you have?

We're certainly happy with the million horsepower, but it's hard to predict what opportunities will come up.

Okay. Thanks.

Our next question comes from Jason Wrangler from Wunderlich. Your line is open.

Hey. Good morning, guys.

Good morning.

Just curious on the stacked portion, maybe just there. Is it pretty split evenly between the Marcellus and Texas? Or is there one side you're seeing kind of more of the equipment going to the yards?

I'd say at a high level it's fairly evenly split. It hasn't changed too much, although Permian is a little bit more active than the Northeast, and you've seen the rig count in the Northeast come down more recently over the last few months. But relatively evenly split for us.

Okay. Thanks. And then just maybe on the CapEx with the reduction. Is there a certain segment that that's coming out over, or is it kind of across the board, as far as just a lower spend throughout this year?

Yes, that's mostly coming out of pressure pumping, because of the reduced activity and more empty days in the calendar.

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

The next question comes from Robin Shoemaker from KeyBanc Capital. Your line is open.

Yes, Andy, how are – good morning.

Good morning.

Wanted to ask about, you've got a revolver credit facility and a term loan facility that come up, expire in September 2017. And usually we've seen companies sort of renegotiate and extend those type of revolvers about a year before they expire. Are you thinking in those terms it doesn’t look like I mean you do have you have drawn down on the term loan facility, but not the revolver. Is there any plan within your liquidity scenario to drawn down on the revolver? Or just given the very different environment we're in now in terms of negotiating new revolving credit facilities, what are your thoughts about extending that $500 million revolver?

So, Robin, that's an appropriate question for John Vollmer, and I'll pass that one over to him.

Great.

Hey, Robin. Typically, we follow the same pattern. When you get near a year from maturity of a given line of credit, you go and redo it. Based on where we are today, we have a lot of cash that would cover most all the term debt that comes to. And we're not seeing a lot of need for revolver borrowings. However, we would expect that we would redo the line of credit and have it going forward.

Okay. Fine. My other question, then, had to do with – down the line here when you are at a point where customer conversations lead to a plan to maybe reactive either a rig or fracturing fleet. In terms of – what would be your criterion, certainly you've got some costs associated with that, whether it's just reactivating equipment or actually hiring people. In terms of the kind of pricing that you would look for or the length of the term, in other words, you would, I'm assuming, want to fully recover those reactivation or rehiring costs. Am I correct in that?

Yes. You're absolutely correct. Whether it's drilling or pressure pumping, we have upfront labor costs that we'll incur that we have to cover. We'll have a little bit of maintenance in CapEx. We don't anticipate that to be any impediment to us, given our balance sheet and our liquidity, but suffice it to say that, especially in pressure pumping it's unsustainable pricing today. And there's certainly no point to activate a crew at today's pricing. It would have to come up significantly to activate a separate crew. In our existing working fleets, we still have days on the calendar. We're still doing a fair amount of 24-hour pumping, but we could do more where it's not 24/7 per se. We still have days on the calendar we could round out. So we just don't have that visibility that the market is allowing the level of pricing to bring new pressure pumping equipment back to work or stack pressure pumping back to work.

Right. Okay. Thank you.

The next question comes from Matt Marietta from Stephens, Inc. Your line is open.

Hey, guys. Thanks for taking the questions this morning and congrats on the cash flows, obviously a very strong number there, when you look at the after CapEx number. Wanted to dig into the CapEx a little bit. I guess when you dig into the segmented information in the drilling side, you went from, call it around $100 million in the rig business down to $12 million sequentially. And I think there was maybe one new build delivered in the fourth quarter, if I'm not mistaken. There could be more carryover. But then in the pumping business we went from $28 million to about $8 million in CapEx there. So I'm trying to understand here the dynamic, and why the guide implies that CapEx relative from 1Q for the remainder of the year is essentially a doubling in a run rate to get to your $170 million, while at the same time the asset utilization is moving lower. Is this an increase from drilling or pumping? Or am I just kind of missing that dynamic, given you reported $21 million in 1Q?

Yes. This is John. It's really just a timing thing, where reduced activity in the first quarter, and we expect it'll be higher in the other quarters. You've seen those kind of fluctuations before in our numbers when we're not activating a lot of new equipment…

So you're deferring CapEx spending? Because activities should continue? I mean, you guys said you're stacking more equipment, and the rig numbers will decrease.

The stacking of the horsepower occurred early in the year. And that's where the decrease is versus what we talked about in February. In terms of drilling, it's roughly in line with what we talked about last quarter. And it's really just timing and spend. There's no other significance to it.

Got it. Okay. Thanks. That's all out of me.

Your next question comes from Darren Gacicia from KLR Group. Your line is open.

Hey, guys. Thanks for taking my question. Good morning.

Good morning.

I wanted to give a quick ask on, clearly everybody assumes that the first rigs that'll go to work will be the AC rigs. You also have a pretty decent sized fleet of SDR rigs. With the rig decline, everything's kind of narrowed into mainly being horizontal drilling. At some point, I would imagine that maybe the mix in that change is a little bit in recovery. How do you look at – what could happen with utilization of the SDR fleet versus the AC fleet and recovery? And how should we kind of map that out if we were to assume if that activity were to start to uptick next year and continue?

So it really depends on how the recovery plays out. And in a strong enough recovery, if commodity price is moving up to incentivize the larger independence with the larger landholdings to drill horizontals, then yes, high-spec apex rigs are going to drive our rig count. But at the same time, at Patterson-UTI, we have one of the broadest bases of customers in the industry. And we still work for some small independents that just have a few wells to drill from time to time. And occasionally you see some of these smaller independents drill just because the costs are low, and certainly much lower than they were in 2014. And so our legacy rigs could work a little bit in different parts of this cycle as well. Now remember, our net book value on these legacy rigs is not that high. But we just keep them for market reasons, because we still have a few of these customers in our portfolio.

Got you. And I know that people have kind of picked around it here, but maybe to add a slightly different way. In terms of reactivating rigs, what would you say is sort of the average reactivation cost per rig? And I ask in part for kind of a directional and part for kind of the modeling perspective, if I want to think about rig counts increasing with you guys.

It depends on the basin, depends on if any mobilization is required. But in general it's going to be mostly about the labor. Two to four weeks of labor. Remember, labor is about two-thirds of our daily cost. But it's about two to four weeks of labor upfront of the rig going out.

Got it. I mean, so there's no upgrades and stuff like that? Or is that something that, if that were to happen, that would be negotiated and paid by the client anyway? Or how does that work?

Correct. Any upgrades over the state of the existing rig is likely covered in the contract.

Excellent. Thank you very much. I appreciate it.

Our next question comes from Brian Uhlmer from GMP Securities. Your line is open.

Hey. Good morning.

Morning.

I have a quick question. About an hour ago, a supplier mentioned that rig got back to work because of some pipe that it was outfitted with, specifically in teleserve. I'm curious if you saw things like that as differentiating factors currently, and if you could speak to that? And whether or not you have a large degree of your rigs kitted out with that type of pipe, and what you think of that in this current market?

I think that interesting technology that does have some specific applications. That technology has been used on our rigs. In fact, some of the testing was done on our rigs. So, you know, we've talked about it in the past. The apex rigs provide a great platform for automation. We don't have automation in our basket of R&D. But we are building rigs that are a platform for automation. We do have them set up and network capable where companies can come in and plug in to our systems and run the types of drill pipe that you're discussing, and other aspects of automation that other companies have done with us in the past as well.

Okay. Thanks. One for John. I had this discussion with another company who is not taking a tax return, and the future value of the cash flow against future earnings offers a higher net present value than claiming your tax refund currently. Can you walk me through how you looked at that and the decision to bring that cash in from the tax refund, as opposed to holding on the balance sheet to use against future earnings?

I'm not sure what alternative you're referring to. Simply on a tax basis, we were able to carry back losses against taxes that were paid in prior years. Had we – for whatever reason not done that, you wouldn't be able to go back and get those earnings – those dollars, quite frankly. So we're happy to have the cash. And…

Okay. Versus carry forward, John. That was my question.

Well, we have carry forwards going on right now too.

Okay. So there's more of an impact of carry over versus specific segments?

Yes, I'm really not sure the alternatives you're thinking about. If we have a carry back, we take the carry back, get the cash back from the federal government. To the extent we have no dollars we can carry back, you carry them forward, which will also defer future taxes. Does that make sense?

Yes, it does. Absolutely. Finally, unrelated to that, could you walk me through, Andy, how you think about the contractor strategy? If you get three- to six-month contracts and you got out to the market and you try and get labor, and labor escalates and exits of what you're expecting, would you expect those escalators to kick in and all contracts to be similar to previous cycles where cost escalation on the labor side will get passed through on a relatively quick basis? Or do you think there might be a structural change in how those are contracted?

Yes, so one thing to remember is that Patterson-UTI, in drilling we have not cut the wages for the individual positions. We say that the labor market's going to be tight, it's going to take time to attract individuals, and we're going to have to staff rigs upfront before they go out. But we don't expect any meaningful increase in those wages right away. We'll have to see how that labor market plays out as things continue to tighten after the industry's put out a number of rigs. But, you know, as of today we're still paying the same wages we paid last year. Remember, there is a labor market around us. Some economists will tell you that energy is the only sector in the U.S. that's suffering right now. So when people leave our sector, they tend to find other work over time. So we have to still pay those same wages at the position level on the rigs.

Okay. I guess, moving forward, would you see the typical margins expand as you get more operating leverage and kind of pull through your fixed cost, and then margins contract a little bit as the labor force tightens and it takes you more to recruit and staff? Is that kind of – would you expect kind of a choppy upturn in the margin front?

No. If there's any increase in our labor costs, these are direct pass-through in the majority of our contracts. So I would anticipate after rigs start to move out that we will see some margin expansion over time after the industry gets to that point. Again, we don't have that visibility yet. We're pleased to see that the rig count is stabilizing, and that's a positive right now. But we just don't have any visibility into anything further that would push that market.

Right. Thanks for your time. Appreciate it.

The next question comes from John Daniel from Simmons. Your line is open.

Thank you. Just a first question on cash margins and compression into Q2. Given that a greater percentage of the working rigs are backed by contracts, I would have thought that the cash margins would have benefited more from the rig mix. Just your thoughts on that point. And can you tell us what you're assuming as your revenue per day in Q2?

The margins are getting tighter. It's getting tougher to control the costs. We have a mix of standby rigs in there as well, and so you've got various things that are driving that, plus the rigs that we've negotiated as they've come off contract. So there's several moving pieces in there.

Okay. Can you share with us what the revenue per day is in that and what's driving cash margins?

What the revenue per day is?

Yes.

Yes, I don't have that in front of me.

Okay. All right. On pressure pumping…

Hey, John.

Yes.

It's Mark. You realize, obviously, and I'm sure everybody else on the call does as well, that as we have fewer rigs running, that in effect, your fixed costs are spread over fewer rigs.

Right.

And that that's one factor of impacting how much your average costs per day are. And in effect, you have to think through that issue a lot.

Okay. Fair enough.

And it flips the opposite way, obviously, in a recovery.

Okay. All right. You mentioned that you would not experience any unusual attrition in the pressure pumping fleet. But you also noted a belief that the natural industry attrition rate is roughly 10%, but could be as much as 20% this year. When you make the statement, any unusual attrition, are you saying you will be more in line with the industry rate of 10%? Or that you don't expect to see any attrition?

I think that our working equipment is more in line with an industry average of 10% per year. Our stacked equipment, we just don’t see any meaningful attrition there. Like I said, a handful of smaller, older 1,800 horsepower pumps, but that’s really it. And that’s not really going to impact the fleet, because those pumps weren’t working that much any ways. But I think that we’ve also seen companies call out equipment being retired, older equipment and that’s why we concur that, as an industry you’re probably seeing 20%, maybe more. It’s hard to know. As you will know, it’s very hard to pin down exactly what it looks like.

That’s impossible.

Okay. But I mean at the end of the day, if you’ve got a million horsepower a day when you file your 10-K for 2016 I’m not going to say 910,000. I just want to make – as we think about your horsepower totals.

No, you’re not going to see that kind of change.

Yes, John, what drives that is the fact that the equipment is not 10 years old, right?

All right. I get it. I was just trying to clarify, that’s all. But then...

Yes, so. The average of about four years...

And, John, I think that one other thought that you’re getting from us in some of that conversation about attrition is the anecdotal information about competitors who are pricing at very low levels and bringing out equipment that’s failing on site.

All right

And thinking to ourselves, that that equipment that’s failing onsite for bids that were unacceptable from our perspective puts that competitor into a very difficult position because we can’t understand how they can then afford to repair that broken equipment since they took the job for less money than it was going to cost them to do it.

All right. They can’t, so, okay. And they’re not, right? Given that...

That’s our point.

Yes, yes. I agree. A couple quick ones for me, since I’m towards the end here. Given the time requirements to put the equipment back to work, two to four weeks getting guys on a rig and up to a month for a frac crew, do you see any indication that you’re going to need to seek an incremental employees by the end of this quarter?

We just don’t have that visibility. We’re happy to say things are stabilizing, but we just don’t see anything further than that. And as I said, and as you well know, pricing is unsustainable in pressure pumping and we certainly wouldn’t want to be activating any crude at today’s pricing. And there’s nothing that’s pushing that pricing up to any level that makes sense to bring out crudes.

All right. Okay. And then the last one from me, how many rigs are on standby today? Is it still 13?

I’m not sure, but I believe it’s around 12.

Okay. Thanks, guys.

Thanks.

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

Thanks. Hi, guys.

Hi.

I guess maybe just one from me, now. And I want to just make sure I put what I all I have heard in the proper context with respect to, again, this industry attrition idea with pumping. If I had understood you correctly, and I’m probably putting some words in your mouth that you’ll want to take back, but I thought I heard maybe last year plus this year might see attrition levels in the order of 20%, which might add to 40%, which would actually be a much bigger number than I think many in the industry have discussed. So I guess, again, I thought I’d throw that at you and see how you respond.

I think, as I stated, we see 10% per year of working horsepower. And then you’ve got horsepower that other companies have called out that they’re writing off as older equipment. And then you’ve probably got a mix in there of horsepower that’s being cannibalized while it’s stacked to provide for utilization of working equipment for companies that have a stressed balance sheet. So we think, could it be more than 20% in 2015 and 2016? Possibly. But it’s very hard to know. But what we want to remind everybody is on our side at Patterson-UTI, we continue to fund the OpEx and the CapEx for maintenance for our own working fleets. And we don’t see any impediments bringing out the stacked horsepower that we have when we do get to some form of recovery.

I appreciate that. And I’m not trying to ask out questions about the industry to say I don’t want to focus on you, but I was trying to understand it. So your aggregate sense of the industry, therefore, is it’s 10% of working – one way to think about it might be 10% of working. Then you start to reach into this grayer area of cannibalization.

Yes.

But if I were to walk away saying, would 20% per year of the gross then be a larger number than you envision? $7.5 million would be a larger number than you envision, I guess, because you’re talking about less attrition on working – at least with the much smaller working number? Am I over thinking this?

No, you’re not over thinking it. But it’s based on what we know. And it’s very hard to know what some of the larger companies are doing and they have the majority of the horsepower. But based on what we know from our own experience and what we’ve read about, what people have announced, we think from our own experience again working horsepower, you’re going to have attrition of about 10% per year. And based on the age of the fleet, then you’ve got other horsepower that’s going to leave the industry for various reasons on top of that.

Right. Okay. Thanks for the color. I’ll turn it back.

The next question comes from Matthew Johnson from Nomura. Your line is open.

Hey. Good morning, gentlemen. Thanks for squeezing me in.

Good morning.

Just one quick one for me on pressure pumping. Just wondering if you could kind of lend your insights with respect to the nature of your own pumping work over the last, I don’t know, few weeks or few months. Is it geared more towards drilled but uncompleted wells? Or just any thoughts you have on what you think the trajectory of the DUC count [ph] is doing out there on some of the basins that you’re working in?

In today’s environment with commodity prices where they are, by far the majority of the work we’re doing is behind drilling rigs. I wouldn’t say that we’re doing any meaningful fracturing of DUC [ph] wells. We hear a lot about them. We do our best to understand what’s out there. But we’re just not seeing any meaningful activity in that area.

Great. Thanks, guys. That’s it for me.

Our next question comes from Mike Breard from Hodges Capital. Your line is open.

Yes, I was just being optimistic, if at some point in the future a potential customer drives past your rig yard or your pumping yard and sees idle equipment, do you think you could possibly still get a day rate increase based on the fact that the labor is hard to find? I mean you don’t have to have the rig count go back to a thousand and get a day rate increase do you?

No, and I think that as we start to put out rigs you’ll see day rates increase. Again, as I stated earlier pricing is a challenge right now and if you’re talking about bringing out a rig that we have in the yard today or a pressure pumping spread that we have in the yard today it needs to be at a higher price than what we are currently working at to incentivize us or most of our peers who want to do that. So you’re right. There will be a time that when you see equipment going out that it’s going to start to move at higher pricing just because of the upfront costs and labor and maintenance and some other things.

Thanks.

[Operator Instructions] Our next question comes from Mark Brown from Seaport Global. Your line is open.

Hi I was wondering, you’ve mentioned your short term view of the activity levels as stable. What commodity prices, oil, natural gas, and I know we don’t talk about natural gas much but I ‘m curious what commodity prices you would think would be necessary to see the activity levels increase?

Yes. So again, we characterize the stabilization at the commodity prices that we see today to get any kind of increase you’d need commodity prices to move up but I think it varies by basin. So it’s hard to really pin it down and say what that is and whether it’s oil or natural gas. Natural gas in the Marcellus may require one number while in the Rockies it may require a different number. But we’re going to avoid calling out what we think that number is just because we think it varies depending on where you are in the U.S. or Canada but it certainly has to be higher than where we are today. With what we have today we see the stabilization but certainly not enough to move activity.

Okay. Thank you. And the other question was you mentioned that most of the fracking is behind a rig, but the DUC [ph] inventory outs, would you believe that because that exists that you’re likely to see activity come back to fracking before rig, or more quickly when we do see a recovery?

It’s hard to know. Every recovery is a little bit different from the other one and the number of DUCs [ph] out there might drive this one a little bit different than previous recoveries. Also from a completion standpoint, we’re concentrated in the northeast and we’re concentrated in Texas, so any DUCs [ph] in the Bakken wouldn’t affect us as a company. But either way, we’re agnostic to that. If you think drilling is coming back first, we’re happy. If you think completion’s coming back first, we’re happy there too. But it’s hard to know exactly which one will come back.

All right. Thank you very much.

The next question comes from John Daniel from Simmons. Your line is open.

Hi, guys. Thanks for putting me back in. First of all on pressure pumping guidance, hopefully you can address this. But are you assuming a deterioration or an improvement in the top line as we progress through Q2?

Deterioration in the top line based on lower utilization of existing crews. In other words, more white space in the calendar.

Got it. And then when you guys go out and are replacing component parts, whether it be engines, transmissions, pumps, et cetera, are you seeing getting longer lives from the newly designed equipment? That’s some of the things we hear when we talk to them. I’m just curious what that magnitude might we.

Deterioration I wouldn’t say we’re seeing any different. But we had moved to a lot of the newer technology in terms of transmissions and couplings and things like that a few years ago, and even upgraded and converted our fleet in some cases to some of the newer transmissions. So in that particular case I wouldn’t say we’re seeing anything different. I think we were pleased with what we were getting from the equipment in terms of reliability. And I think it’s one of the reasons we’re still very operationally efficient, and one of the reasons we’re still working as many crews as we are today.

Okay. And then as we fast-forward through this year and get closer to the Tier 4 compliance date, with your ability to spin the money to upgrade fleets, do you think that’ll distill into a competitive advantage versus the peers, or not?

Yes, Tier 4 will come in different parts of the country at different speeds. We have one Tier 4 complete frack fleet. Not just a few engines, but a complete spread. And it’s not hard for us to upgrade if required, based on our balance sheet.

Okay. All right. That’s all. Thanks, guys.

Thanks.

The next question comes from Jim Wicklund from Credit Suisse. Your line is open.

Better late than never.

Hey, Jim.

Guys, you look at Schlumberger, somebody mentioned earlier Schlumberger is thinking about building rigs. Haliburton has got an international deal with Trinidad. NOV on their call today talked about how they basically had their versions of smart rig, and the land drilling contractors need to differentiate themselves in order to compete. Is land drilling going to be part of an integrated package in five years, or is it still going to be a stand-alone service looking very much like it does today?

You know, Jim, there’s no questioning who the integrator is, especially in North America, and it’s the E&P. The E&P likes to differentiate themselves by selecting their service providers, and we just – we haven’t seen bundling. Bundling has been talked about for years. We see it more outside of North America than we do in North America. And I don’t think that changes over five years. I think will some of these technologies have some uptake? Sure. Does that mean we’re not competitive? No, not by any means. If you look at our rig performance out there today in any basin, what you see is top performance, and at the end of the day…

That’s the way you work, I know. I know. That not only works for the most efficient rigs and the most efficient well drills. Is that – but that’s part of it. I mean you would think the people who are best at it would be the ones that everybody would to be as their integrated partner, if you would, but you’re saying if the E&P companies are going to continue to be the prime contractor, and he’ll just have a bunch of subs including land rigs?

I think it continues that way in North America.

Okay. I very much appreciate that. Second question, if I could. Internationally you guys looked at a rig package a couple years ago, you opened a little office in the Middle East. You all have said before that there’s some future for the company internationally. Obviously now international is getting hit not as bad, not as – a little bit later than the U.S., and I have no clue as to the opportunities out there, but do you guys still see international as an opportunity in the future for Patterson at least as long as me and Mark are going to be alive and kicking?

When we first started talking about international, we said it was long term. It’s still long term. The market hasn’t necessarily cooperated so much for us, but we still see it as a long term growth opportunity for the company.

Okay. So there’s nothing that’s going to happen in the next few years? Mark and I don’t have to worry about that, right?

Jim, speak for yourself. [Indiscernible] time thinking about it.

It’s a bit childhood so I shouldn’t complain.

All right.

Okay. Last question, if I could. Everybody has talked about consolidation in different parts of the business, and there’s always culture issues between companies. Should we expect to see any kind of consolidation in the global land rig business over the next couple of years?

Yes Jim I’m unable to really speculate on that. It’s one of those things which we hear lots of talk about it, and quite frankly I don’t think that any of us really knows what’s going to happen.

Okay. Okay, thank you for the definitive answer, Mark. I appreciate it, guys. Andy, I thank you very much. Appreciate it, guys.

I am showing no further questions at this time. I would now like to turn the call over to Mr. Mike Drickamer for closing remarks.

Actually it’s going to be me who’s going to close. I’d just like to thank everyone for joining us on Patterson UTI’s first quarter 2016 conference call. We look forward to your joining us at the – for our call with regard to the second quarter of 2016. Thanks, everybody.

Ladies and gentlemen, thank you for participating in today’s conference. This concludes the program. You may all disconnect. Everyone have a great day.