Patterson-UTI Energy Inc (PTEN) 2016 Q1 法說會逐字稿

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, Antwon. Good morning, and on behalf of Patterson-UTI Energy I would like to welcome you to today's conference call to discuss the results of the three months ended March 31st, 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 state the Company's or Mangement's plans, intentions, beliefs, expectations, or predictions for the future are forward-looking statements within the meaning of the US Private Securities and 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 for what the Company expects.

The Company undertakes no obligation to publicly update or revise any forward-looking statement. The Company's SEC filings may be obtained by contacting the Company or the SEC, and are available through the Company's website and through the SEC's EDGAR system. Statements made in this conference call include non-GAAP financial measures. The required reconciliations to GAAP financial measures are included on our website, www.PATenergy.com, and in the Company's press release issued prior to this conference call.

And now, it is 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 deep 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 earning 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 remained 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 will now turn the call over to Andy.

Thanks, Mark. In Contract Drilling our rig counts during the first quarter averaged 71 rigs in the US and 3 rigs in Canada, compared to 88 rigs in the US and 3 rigs in candidates during the fourth quarter. During the first quarter total Contract 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 costs per day decreased to $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 quarter as we had an average of 13 rigs on standby in the first quarter. As a reminder, rigs on standby have very little associated costs thereby reducing the overall average rig operating cost per day.

Total average rig margin per are 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 31st we had term contracts for drilling rigs providing for approximately $580 million of future dayrate drilling revenue.

Based on -- (Audio Drop). 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 continued to generate positive adjusted EBITDA from 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 at 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 1 million frack horsepower 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 has an average age of four 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 to 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 magnitudes 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, both drilling and Pressure Pumping we remain very focused on reducing costs and protecting our balance sheet. With respect to our capital spending, we will 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 EMP impairments will decrease approximately $4 million per quarter for the remaining three quarters of 2016. For the second quarter depreciation and expense excluding EMP 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 refund 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 US 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 US drilling and completion activity.

The outlook for crude oil prices remains uncertain, with numerous economic and geopolitical risks and opportunities. Therefore, visibility in 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 will 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 weather this downturn and succeed during the next recovery.

With that, I would like to both commend and thank the hard-working men and women who make up this Company. I and the Management Team appreciate your efforts during this challenging market environment. Operator, we would like to now open the call for questions. Antwon?

Yes. Thank you. (Operator Instructions). One moment for questions. Our first question comes from Sean Meakim from JPMorgan. Your line is open.

Hey. Good morning.

Good morning.

So you guys are getting inbound 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 the comparing contrasting last year versus this year. Just how those conversations are going.

I think in terms of last year if you are referring to the June time frame when crude was trading in the $60 or $62 level versus where we are today, it is not quite the same. You know, what we see today and the visibility we currently have, is around stabilization of activity; both drilling and Pressure Pumping given today's commodity prices, but we are a record low rig count. We do not 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 are still in a tough environment.

I think that is very fair. And so then as we think about when a recovery does get under way at some point, how are you thinking about -- traditionally we would see drilling activity lead completions activity, but it seems like a lot of speculation that we would see perhaps more of a recovery coinciding with -- in pumping coinciding with drilling. Just curious to hear your thoughts there as well.

Well, I guess I will 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 in that $60 or $62 level we were getting phone calls both in our drilling business and in our Pressure Pumping business and it will just be interesting to see how this plays out, but it could be very similar. But again we are 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 from Raymond James. You may proceed.

Good morning, guys. I find a little odd saying you all did a great job in a quarter when we are still losing $70 million, but you all did do a remarkable job on the cost side. And that is my first question is how -- where did the cost reductions come from? Is it reduced labor force or is it coming from vendors or -- or -- help me understand how you all were able do I guess 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. You know, it is not any one single thing. You know, certainly with the decrease in activity we continue to scale the business so that we are the appropriate size company for the activity that we have in general.

You know, especially when look at drilling we are still paying the same wages that we were paying for the positions. Unfortunately, many of our people, and in fact most of our people at this point, have had to take lower on the rigs. But you that, you know, base daily wage cost at the rig level is still roughly the same. We have continued to negotiate with suppliers.

I would not say that we are getting, you know, 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 respect. So, you know, we continue to attack it on several fronts. It is a tough environment. The rig count is very low right now and we are doing what we can to try to keep our costs in line.

Okay. Switching gears you have got apparently about a million horsepower Pressure Pumping and there is a lot of, as you mentioned, speculation on attrition and whatnot. Is it -- am I reading you correctly when you are saying all your stuff go back to work. Have you had any attrition at all or is all of that million horsepower good to go without meaningful investment if -- if we turn the go button on tomorrow?

So the little bit of attrition we have had, and I will describe it as deminimous; a few older 1800-horsepower pumps, but that is really about it. You know, we expect, really almost all of the equipment that we have stacked can go back to work. There will be some maintenance costs, there will be some CapEx costs. You know, we do not see these as unreasonable costs going forward.

It is one of the reasons that we are focused on cash and liquidity and making sure is that we are well-positioned for a recovery, but the average age of our fleet is four years old. You know, mostly new Quinn complex pumps. We feel like we are in good shape for when that recovery does happen, although we do not have that visibility yet.

All right. Just one quick follow-up on that. Where do you see -- in a recovery scenario certainly we envision for 2017 -- where do you see the bottlenecks involving? 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 is going to have the same problem we are going to have. I think it is 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.

You know, when you look at how far we have declined, our rig count's come down, over 75% now for us, when you look at the people that unfortunately we have had to release; you know, people that have left our Company in the last six months there is a good chance we will get a fair number of those back, but once, you know, people have been gone from our industry for more than six months and certainly I think our case these are a lot of hard working men and women, they are very likely to find work elsewhere at that point.

If we are 4 on 30 rigs today can we get back to a thousand rigs a year from now?

You know, I think that is really going to depend on the market. It is going to depend on what commodity prices are doing, and, you know, 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 Sayed from Goldman Sachs. Your line is open.

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

You know, it is not out of the question to add 20 rigs per quarter. You know, I am reluctant to call out a number because it depends on various factors. We could do even more than 20 rigs if we need to. You know, when it comes to labor we recruited nationally in the past, we will recruit nationally again to bring 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 on. When you look at Pressure Pumping fleets, you know, we need the crews almost a months in advance to get everything ready. So it varies by the business line, but as I mentioned early organization -- from an organization standpoint and the leadership and management we have in place today, we are ready for those challenges, but we will have some, you know, 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 do not really see us spot market. You know, there is not at this trade where you have EMPs out there taking multiple bids for putting up new rigs including mobilization and all the associated costs to take a rig to stack. You just do not see that in today's market. We see stabilization. So it is not really a spot market.

And then, you know, at today's pricing it is difficult to be incentivized to put a new rig out, and especially on the Pressure Pumping side. You know, Pressure Pumping pricing is unsustainable at this point. You know, we are slightly EBITDA-positive, but in Pressure Pumping; if you look at the cash and you include EBITDA, CapEx and G&A, it is slightly nailing. It is an unsustainable situation from pricing from Pressure Pumping.

Yes. But on the drilling side, you know, rates we hear that rates are probably in the $15,000 to $17,000 day range for AC rigs; and first do you concur with that and if that is the case, you mentioned there is very limited spot market data, but if that is the range, would you be interested in adding your rigs at that price range?

When it comes to rig rates, I think what you are hearing are more anecdotal comments. We are still going through negotiations with customers. When we keep a rig running and it is -- it is not so much of a spot rate discussion. Like I said, you know, it is more of a negotiation and it depends on the customer, depends on mobilizations, it depends on the basin you are in, but I think -- I think a lot of what you hear is more anecdotal, and you are going to hear different numbers from different parts of the US right now.

And just my final question, that you know 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 and all that, and one of your competitors -- NOV (inaudible) -- are all working on that. How do you she impacting the -- the rig demand going forward, and what is PTEN's 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 are very proud of the operational performances that we have at Patterson-UTI both in drilling and Pressure Pumping. And in drilling especially, you know, our performance is really driving our rig count as well. You know, and 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 is some companies working on some interesting technology, but I am very comfortable with the programs that we have in place and the selective technologies that we are working on to ensure that our rigs will continue to be competitive from a performance standpoint.

Is this something that you can discuss one of those selective technologies?

You know, I do not think we will go into the details today, but as I said, I am comfortable that we will be competitive just as we are today.

Thank you very much.

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

Hey. Good morning, guys.

Hi Mark.

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

No, that does not really work out, you know, majority of our contracts were signed, you know, in 2013 and 2014. A lot of what you are 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 those numbers would not get you there.

Okay. Okay. Thanks, Andy. And I guess maybe one for Mark or -- or whoever, but now with the dividend adjustment, it 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, Mark. 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, very respectful of that. As we have said at each Board meeting we consider the dividend, 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 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 of from an M&A perspective?

You know, I guess it is fair to say, Mark, with the disruption that is gone throughout the industry that there is opportunities across the whole spectrum. The really interesting circumstance for our 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 is 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 which -- not what particular act -- opportunity is in front of us.

Okay. We will be eagerly awaiting. Thank you.

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

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

You know, we started getting that question from customers early in 2015, but a term contract is a term contract. We will work within the boundaries of that contract, but we do not just adjust rates within a term contract.

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

No. That is -- what is 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 quantity the reactivation costs either on like a per-spread or per-horsepower basis needed between -- for your stacked horsepower between just accruing it up, making all the repairs and so on?

You know, it varies by, you know, the size of the frack fleet and the basin that we might be he 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 do not see these kind of dollars as detrimental to our ability to put equipment out in a recovery. It is one of reasons that we are focused on liquidity and cash rights now.

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

$170 million for the CapEx plan right now.

Is there -- is there anything going on towards the back.end of the year that it is so back half-weighted?

It is not that things are going on toward the back end. You know, we spend dollars in terms of cash out in various quarters on various items, so it is not cash that just moves steady quarter-over-quarter, but the 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 to Andy is for you following up on comments you made about attracting labor back to the industry and after six months or so that can become difficult. I think what is challenging in this environment given the steep declines in rig activity, you know, looking back even all the way back in December we were running 550 rigs according to the Baker account on the horizontal side. As we look out in the second half and assume we start so see some rig recovery, is 550 horizontal rigs a reasonable number to start to think about; if we move past that we will start so see some real friction in terms of attracting labor back?

You know, it is 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 will attract a majority of that labor back in the market. We will also bring in new people to the industry from different parts of the US, but as mentioned earlier we also have the organizational capacity as a Company to get the people that we need. But in terms of the various lists of items that are going to make it challenging in a recovery, labor is at the top of the list.

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

Well, we certainly appreciate your comments and we do think we are 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 recruited in the past. If you remember before the downturn, you know, half the people we were recruiting for a few years before the downturn were active returning military and I think our reputation in those places are still good. So, you know, I think that we will have success in getting the people, but, again, that will 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 have 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.

I have a question just on what you are seeing out therein terms of Pressure Pumping intensity. I think the old rule of thumb used to be one Pressure Pumping accrue could sort of serve three to four rigs. 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?

You know, in general it varies by basin. We do not track that kind of statistic too much. You know, when you are running the Pressure Pumping business focused on completion you are really staying close to the customers in terms of what they are anticipating, and it can even vary by customer just because of pad layouts or other reasons. And you know, in terms of overall intensity I also think in terms of what we are pumping in sand volumes and 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 are running in the different basins on pumping between the Marcellus and the Permian?

You know, not much to say other than, you know, the amount of equipment that we stacked has not changed much in the last three months. You know, in the first quarter we did stack a fair amount but we are -- we have 54% stacked. Our revenues are forecasted to continue to decline and it is 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 would be able to fill those days in the calendar with existing crews, but it is really about utilization right now in the calendar.

Okay. And then this last one would you -- is there any chance that you increase your pumping exposure during this downturn, or are you pretty happy with the million horsepower you have?

You know, we are certainly happy with the million horsepower, but it is hard to predict what opportunities will come up.

Okay. Thanks.

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

Hey. Good morning, guys.

Good morning.

Just curious on the stack portion maybe just there. Is it pretty split evenly between the Marcellus in Texas or is there one side you are seeing kind of more of that equipment going to the yards?

You know, I would say at a high level it is fairly evenly split. It is -- you know, it has not -- it has not changed too much although Permian, you know, is a little bit more active than the northeast and you have seen the rig count in the northeast come down more recently over the last few months but relatively evenly split for us.

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

Yes. That is mostly copping out of Pressure Pumping because of the reduced activity and more empty days in the calendar.

Okay. Perfect. I will turn it back. Thank you.

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

Yes. Andy, good morning.

Good morning.

I wanted to ask about you have got a revolver credit facility and a term loan facility that come up -- expire in September of 2017, and usually we have seen companies sort of re-negotiate and extend those type of revolvers about a year before they expire. Are you thinking in those terms? It does not 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 draw down on the revolver? Or just given the very different environment we are in now in terms of negotiating new revolving credit facilities, what are your thoughts about extending that $500 million revolver?

So, Robin, that is an appropriate question for John Vollmer and I will pass that one over to him.

Great.

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

Okay. Fine. My other question then had to do with, you know, down the line here when you are at a point where customer conversations lead to -- to a plan to maybe reactivate either a rigor fracturing fleet in terms of -- what would be your criterion? Certainly you have got some costs associated with that, whether it is 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 am assuming, want to fully recover those reactivation or re-hiring costs and -- am I correct in that?

Yes, you are absolutely correct. You know, whether it is drilling or Pressure Pumping we have up front labor costs that we will incur that we have to cover. You know, we will have a little bit of maintenance and CapEx. You know, we do not anticipate that to be any impediment forgive on our balance sheet and our liquidity, but suffice it to say that especially in Pressure Pumping it is unsustainable pricing today and there is certainly no point to activate a crew at today's pricing. You would have to come up significantly to activate a separate crew.

You know, in our existing working fleets we still have days in the calendar. You know, we are still doing a fair amount of 24-hour pumping, but we could do more. It is not 24/7 per se. We still have days in the calendar we could round out so, you know, I -- we just do not have that visibility that the market is, you know, allowing the level of pricing to bring new Pressure Pumping equipment back to work -- or stacked 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 congratulations on the cash flow. It is obviously very strong number there when you look at the CapEx number. I wanted to dig into the CapEx a little bit. I guess when you dig into the segmented information on the drilling side you went from call it around $100 million in the rig business down to $12 million sequentially. I think there was maybe one new build delivered in the fourth quarter if I am not mistaken, there could be more carryover -- but then the pumping business we went from $28 million to about $8 million in CapEx there. So I am 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, you know, while at the same time the asset utilization are 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 is really just a timing thing. We reduced activity in the first quarter and we expect it will be higher in other quarters. You have seen those kind of fluctuations before in our numbers when we are not activating a lot of new equipment.

But you are deferring CapEx spending? Because activity should continue when you guys said that you are stacking more equipment in the rig will decrease.

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

Got it. Okay. Thanks. That is all out of of me.

The 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, you know, clearly the -- everybody is the first rig will go to (inaudible). You also have a pretty decent size fleets of (inaudible) rigs. You know, with the rig decline everything is kind of narrowed in the mainly being horizontal drilling at some point I would imagine, you know, maybe -- maybe there is the mix changers a little bit in recovery. You know, how do you look at what could happen with utilization at the SVR fleet versus the A fleet in recovery; and how should we kind of map that out if we were to assume that activity would 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 prices move enough to incentivize the larger independents with the larger land holdings 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, you know, in different parts of the cycle as well. Now, remember our -- 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 those customers in our portfolio.

Got you. And I know people have kind of picked around in here but maybe asked a slightly different ways. 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, part for a modeling perspective if I want to think about rig counts increasing for you guys.

You know, it depends on the basin. You know, it would depends on if anybody mobilization is required, but in general it is going to be mostly about the labor. You know, two to four weeks of labor. Remember labor is about two-thirds of our daily costs, but it is about two to four weeks of labor upfront of the rig going out.

Got it. So I mean there is no upgrades and stuff like that or is that something that -- if that were to happen that would be negotiated and paid by 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 had a quick question. About an hour ago a supplier mentioned that rig got back to work because of some pipes that it was outfitted with, specifically Intelliserve. I was 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 fitted out with that type of pipe and what you think of that in this current market.

So 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 we talked about it in the past. The APEX rigs provide a great platform for automation. We do not 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 with come in and plug into our systems and run the types of drill pipe that you are discussing and other aspects of automation that other companies have done with us in the past as well.

Okay. Thanks. One for John, and I had this discussion with -- with another company who is not taking a tax return and, you know, the kind of the future value of the cash flow against future earnings offers a higher net present value than claiming your tax refund currently. Could 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 it on the balance sheet to use against future earnings?

I am not sure what alternative you are referring to. You know, simply 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 would not be able to go back and get those earnings. Or those dollars quite frankly. So we are happy to have the cash and --.

Okay. Versus -- versus carryforward, John, was my question.

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

Okay. So it was more of an impact of carryforward versus specific segments?

Yes. I am really not sure of the alternative you are 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 can you walk me through, Andy, how you think about the contracting strategy? If you get three to six months contracts and you -- you go out to the market and you try and get labor and labor escalates in excess of what you are 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 any that 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 is going to be tight, it is going to take time to attract individuals. You know, we are going to have to staff rigs upfront before they go out, but we do not expect any meaningful increase in those wages right away. We will have to see how that labor market plays out as things continue to tighten after the industry has put out a number of rigs.

But as of today we are still paying the same wages we paid last year. Remember, there is a labor market around us. You know, some economists will tell you that energy is the only sector in the US that is suffering right now, and 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 costs 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 is any increase in our labor costs these are a 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. You know, again, we do not have that visibility yet. We are pleased to see that -- that the rig count is stabilizing and that is a positive right now, but we just do not 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 the 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 are assuming as your revenue per day in Q2?

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

Okay. Can you share with us what the revenue per day is and the statement driving cash margins?

What the revenue per day is?

Yes.

I do not have that in front of me.

Okay. All right. On Pressure Pumping.

Hey this is Mark. You realize obviously and I am sure everybody else on the call does as well that as we have fewer rigs running, that in effect your fix is costs or spread over fewer rigs.

Right.

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

Okay. Fair enough. Fair enough.

And flips the opposite way obviously in a recovery.

Okay. All right. The -- 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 that you will be more in line with the industry rate of 10% or that you do not expect to see any attrition?

I think that our working equipment is more in line with an industry average of 10% per year. You know, our stacked equipment we just do not see any meaningful attrition there. Like I said a handful of smaller older 1800-horsepower pumps, but that is really it, and that is not going to impacts the fleet. Because those pumps were not working that much anyways.

But I think that we have also seen companies call out equipment being retired, older equipment, and that is why we concur that as an industry you are probably seeing 20%, maybe more. It is hard to know. You know, as you well know it is very hard to pin down exactly what it looks like.

It is impossible. Okay, but at the end of the day if you have got a million horsepower per day when you file your 10-K for 2016, it is not going to say 910,000? I just want to make -- as we think about your horsepower totals.

No you are not going to see that kind of change.

John, what driver that is the facts that the equipment is not 10 years old, right.

All right. I get it. I was just trying to clarify. That is all.

Yes so the average four years.

And John I think one other thought that you are getting from us is some of that conversation about attrition is the anecdotal information about competitors who are pricing it very low levels to bringing out equipment that is failing on-site, and thinking to ourselves that that equipment that is failing on-site at bids that were unacceptable from our perspective puts that competitor into a very difficult position, because we can not 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 not. Okay. And they are not, right? Given the --

That is our point.

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

We just do not have that visibility. You know, we are happy to say things are stabilizing, but we just do not see anything further than that and as I said, you know, as you well know pricing is unsustainable in Pressure Pumping and we certainly would not want to be activating any crews at today's pricing and there is nothing that is pushing that pricing up to any level that makes sense to bring out crews.

Okay. Then the last one for me how many rigs are on standby today? Still 13?

I am not sure but I believe it is 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 for me now. I want to just make sure I put what I thought I heard in the proper context with respect to again this industry attrition idea with pumping. If I understood you correctly, and I am probably putting some words in your mouth that you will 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; then I think many in the industry have discussed. So I guess again I thought I would throw that out and see how you respond.

You know, I think as I stated we see 10%, you know, per year of working horsepower and then you have got horsepower that other companies have called out that they are writing off as older equipment, and then you probably got a mix in there of horsepower that is being cannibalized while it is stacked to provide for utilization of working equipment for companies to have express balance sheet.

So we think could it be more than 20% in 2015 and 2016? Possibly. But it is very hard to know. But what we want to remind everybody is on our side, Patterson-UTI, we continue to find the OpEx and the CapEx for maintenance from our own working fleets, and we do not see any impediments to bringing out the stacked horsepower that we have when we do get to some form of recovery.

I appreciate that, and I am not trying to ask you questions about the industry to say I do not want to focus on you, but I -- but I was trying to understand it. So your aggregate sense of the industry therefore is 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.

Correct.

If I were to walk away saying -- okay so 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 are talking about different -- you are talking about less attrition on working at least the much smaller working number. Am I over thinking this?

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

Right. Okay. All right. Thanks for the color. Turn it back.

The next question comes from Matthew Johnston from Namora. Your line is open.

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

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 wor kover the last I do not know, few weeks or few months. Is it geared more towards drill but uncompleted wells or just any thoughts you have on what you think the trajectory of the duct count is doing out there and some of the basins that you are working in?

You know, in today's environment with commodity prices where they are the -- the by far the majority of the work we are doing is behind drilling rigs. I would not say that we are doing any meaningful fracturing of duct wells. We hear a lot about them. You know, we do our best to understand what is out there, but we are just not seeing my meaningful activity in that area.

Great thanks, guys. That is it for me.

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

Yes. Just being optimistic at some point in the future a customer -- potential customer drivers past your rig yard or your pumping yard and sees idle equipment, do you think you could possibly still get a dayrate increase based on the fact that labor is hard to find? I mean you do not have to have the rig counts go back to a thousand to get a dayrate increase, do you?

No. And I think that as we start to put out rigs, you will see dayrates increase. You know, again, as I stated earlier, pricing is a challenge right now and if you are talking about bringing out a rig that we have in the yard today, or Pressure Pumping spreads 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 to want to do that.

So you are right. There will be a time when you see equipment going out that it is going to start to move at higher pricing just because the upfront costs and labor and maintenance and some other things.

Okay. Thank you.

Thanks.

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

Hi. I was wondering you have mentioned your short-term view of the activity levels as stable. What -- what commodity price is oil, natural gas; and I know we do not talk about natural gas much, but I am 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 would need commodity prices to move up. But I think it varies by basin. So it is hard to really pin it down and say what that is and whether it is, you know, oil or natural gas. You know, natural a gas in the Marcellus may require one number while in the Rockies it may require a different number. But, you know, it is -- you know, we are going to avoid calling out what we think that number is just because we think it varies depending on where you are in the US 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 duct inventory -- would you believe that because of that exists that you are likely to see activity come back to fracking before rig, or more quickly when we do see a recovery?

It is hard to know. You know, every recovery is a little bit different from the other one and the number of ducts out there might drive this one a little bit different than previous recoveries. Also from a completion standpoint, you know, we are concentrated in the northeast and we are concentrated in Texas, so ducts in the Bakken would not affect us as a company but either way we are agnostic to that. If you think drilling is coming be back first, we are happy. If you think completion is coming back first, we are happy there, too. But it is 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.

Hey, guys. Thanks for are 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 topline as we progress through Q2?

A deterioration in the topline 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 replacing component parts for the engines, transmissions, pumps, et cetera are you getting longer lives from the newly designed equipment that some of the things that we hear when we talk to them? I am just curious what that magnitude might be.

You know, I would not say we are seeing any different, but we had moved to a lot of the newer technology in terms of an couplings and things like that a few years ago, and even upgraded and converted our fleet in some cases to some of the newer transitions. So in that particular case, I would not say we are seeing anything different. I think we are pleased with what we were getting from the equipment in terms of reliability and I think it is one of the reasons we are still very operationally efficient and one of the reasons we are still working as many crews as we are today.

Okay and as we fast forward through this year an get closer to the Tier 4 compliance date, with your ability to spend the money to upgrade fleets, do you think that it will distill in the competitive advantage versus the peers or not?

Yes. You know, Tier 4 will come indifferent parts of the country at different speeds. We -- we have one Tier 4 complete frack fleet, not just a few engines but a complete spread, and it is not hard for us to upgrade if required based on our balance sheet.

Okay. All right. That is 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, Halliburton has got an international deal with Trinidad, NOV on their call today talked about how they he basic had disease of the 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 standalone service looking very much like it does today?

You know, Jim, there is no question who the integrator is especially in North America and it is the EMP. You know, the EMP likes to differentiate themselves by selecting their service providers and we just -- you know, we have not seen bundling. Bundling has been talked about for years. We see it more outside of the North America than we do in North America and I do not think that changes over five years.

I think will be will some of these technologies have some uptick? Sure. Does that mean we are not completive? No. Not by any means. You know, if you look at our rig performance out there today in any basin, you know, what you see is top performance and --

But you all still win the awards. I know. You all still win the awards for the most efficient rigs and the most efficient well drill. But that is part of it. I mean you would think that the people who are best at it would be the ones that everybody would want to be as their integrative partner if you would. But you are saying the EMP companies are going continue to be the prime contractor and he will 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 is some future for the company internationally. Obviously now international is getting hit not as bad as -- a little bit lighter than US, and I have no clue with 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?

You know, when we first started talking about international, be said it was long-term. It is still long-term. The market has not necessarily cooperated so much for us, but we still see it as a long-term growth opportunity for the Company.

Okay. So there is nothing that is going to happen in the next couple years. Mark and I do not have to worry about that, right?

Jim, speak for yourself. (Multiple Speakers). I had a good childhood so I should not complain.

All right.

Okay our. Last question if I could everybody's talked about consolidation and different parts of the business and there is 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?

You know, Jim, I am -- you know, unable to really speculate on those. It is one of those things which we hear lots of talk about it and quite frankly I do not think any of us really knows what is going to happen.

Okay. Okay. Thank you for the definitive answer, Mark. I appreciate it guys. Andy, 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 is going to be me who is going to close. I would just like 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.