Patterson-UTI Energy Inc (PTEN) 2016 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Patterson-UTI Energy Q3 2016 earnings conference call. (Operator Instructions) As a reminder, this conference is being recorded.

I would like to turn the call over to Mike Drickamer, Director of Investor Relations. You may begin.

Thank you, Tara. Good morning, and on behalf of Patterson-UTI Energy, I'd like to welcome you to today's conference call to discuss the results of the three and nine months ended September 30, 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 US Private Securities Litigation Reform Act of 1995, the Securities Act of 1933, and the Securities Exchange Act of 1934. These forward-looking statements are subject to risks and uncertainties as disclosed in the Company's annual report on Form 10-K and other filings with the SEC.

These risks and uncertainties could cause the Company's actual results to differ materially from those suggested in such forward-looking statements or what the Company expects. The Company undertakes no obligation to publicly update or revise any forward-looking statement. The Company's SEC filings may be obtained by contacting the Company or the SEC and are available through the Company's website and through the SEC's EDGAR system.

Statements made on this conference call include non-GAAP financial measures. The required reconciliations to GAAP financial measures are included on our website, www.patenergy.com, and in the Company's press release issued prior to this conference call.

And now it 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 third quarter of 2016. We are pleased you are able to join us today.

As is customary, I will start by briefly reviewing the financial results for the quarter ended September 30. 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 third quarter, as set forth in our earnings press release issued this morning, we reported a net loss of $84.1 million or $0.58 per share on revenues of $206 million. Total adjusted EBITDA during the third quarter was $40.1 million.

We previously announced that in July, we used cash on hand plus $70 million of borrowings from our revolving credit facility to repay the entirety of our $230 million in bank term loans outstanding at June 30. Since July, we have used cash on hand plus cash generated during the third quarter to reduce the outstanding borrowings on our revolving credit facility to $15 million at September 30.

Despite the difficult market conditions, during the nine months ended September 30, 2016, we generated sufficient cash flow to reduce our net debt by approximately $165 million. Accordingly, debt to total capitalization at September 30 improved to 21%, and we do not have any term maturities until October 2020.

Related to the repayment of our bank term loans in July, included in our third-quarter interest expense is a charge of approximately $1.4 million pre-tax or $866,000 after-tax for the write-off of deferred financing costs. Without this charge, EPS would have been a loss of $0.57.

With that, I will now turn the call over to Andy.

Thanks, Mark. In contract drilling, our rig count during the third quarter averaged 60 rigs in the US and 2 rigs in Canada, up from the second-quarter average of 55 rigs in the US and less than 1 rig in Canada. Our rig count continues to improve, and for the month of October, we expect our rig count will average 63 rigs in the US and 2 rigs in Canada.

Total contract drilling revenues were $124 million, including $1.1 million of revenues from early contract terminations. These early contract terminations positively impacted our average rig revenue per day of $21,870 by $200. Excluding early termination revenues, average rig revenue per day during the third quarter would have been $21,670 compared to $21,980 in the second quarter.

Total average rig operating costs per day during the third quarter increased to $13,180 from $12,770 in the second quarter due to a decrease in the proportion of rigs on standby. During the third quarter, rigs on standby represented approximately 13% of revenue days, down from 19% in the second quarter.

Total average rig margin per day during the third quarter was $8,690. Excluding the positive impact from early termination revenues, total average rig margin per day during the third quarter was $8,490 compared to $9,210 during the second quarter.

At September 30, we had term contracts for drilling rigs providing for $464 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 fourth quarter. And an average of 32 rigs operating under term contracts during 2017.

Looking forward, assuming commodity prices remain at or above recent levels, we believe US rig counts will continue to increase. During the fourth quarter, we expect our rig count will average 65 rigs in the US, an increase of 8% from the average for the third quarter. In Canada, we expect our rig count will average two rigs during the fourth quarter.

Average rig revenue per day, excluding any possible early termination revenues, is expected to be $21,500 during the fourth quarter. This expected decrease of less than $200 is a function of rigs being reactivated and the re-contracting of rigs rolling off higher-rate term contracts.

This expected decrease will be partially offset by a smaller proportion of rigs on standby, as we expect to average only 4 rigs or 6% of total revenue days on standby during the fourth quarter. The smaller proportion of rigs on standby is also expected to contribute to the expected increase in average rig operating costs per day, which is expected to average $14,000 in the fourth quarter.

Our rig count in the US has improved by a net 12 rigs or 23% from the low in late April. This net 12 rig increase consists of 18 rigs reactivated, while 6 rigs have been idled. All the rigs that have been reactivated are AC-powered APEX rigs, including 17 1,500-horsepower rigs. Of the 18 rigs reactivated, 15 had walking systems and 13 had 7,500-psi circulating systems.

In total, 12 of the 18 rigs reactivated were 1,500-horsepower rigs with a 750,000-pound mass rating, a walking system, and 7,500-psi circulating system. Within our fleet, a total of 52 rigs have these capabilities, of which 48 are currently contracted for 92% utilization. In West Texas, which has been the source of most of the incremental high-spec rig demand, all of our rigs with these capabilities are contracted.

Across the industry, we believe there are a limited number of the most capable rigs. We estimate approximately 300 of these rigs across the US that are 1,500-horsepower rigs with a 750,000-pound mass rating that are pad capable and have a 7,500-psi circulating system for longer laterals.

Early increases in the rig count were initially driven by smaller operators that were drilling less service-intensive wells. However, we believe the market has transitioned, with recent increases in the rig count being driven by higher-spec drilling rigs, which is increasing the utilization and decreasing the availability for this class of rig, especially in the Permian Basin.

We are justified we will further upgrade our fleet to meet customer demand for higher-spec rigs. We have 40 1,500-horsepower APEX rigs that can be upgraded to these specifications by adding a 7,500-psi circulating system, which is approximately a $1 million upgrade.

We have another 36 1,500-horsepower APEX rigs in our fleet that would require either a walking system or both a walking system and a 7,500-psi circulating system for a total potential upgrade cost per rig of approximately $3 million. Given the increasing utilization for these higher-spec rigs and the capital required to upgrade rigs to these capable, we expect day rates to increase as activity continues to grow.

Before moving on to pressure pumping, I would like to briefly discuss the acquisition of Warrior, which we closed in September. Our total investment in the Warrior transaction was around $20 million and includes the acquisition price, which was funded with equity as well as cash used to repay Warrior's outstanding debt and cash injected into the company for operating purposes.

Initially, we evaluated Warrior as a potential supplier of top drives as we were attracted to their new 500-ton top drive. Compared to similar sized top drives in the industry, Warrior's new top drive generates higher torque and has greater redundancy, thereby offering higher reliability.

In addition to the top drive and many other innovative technologies in their portfolio, Warrior provides a platform to service and recertify top drives manufactured by both Warrior and other third parties. We have begun the process of expanding the capacity of their top drive service center in the United States and we plan to transition the maintenance and recertification of our existing fleet of top drives to this facility, which should provide a more efficient and cost-effective solution.

We intend to continue operating Warrior as a stand-alone basis. Warrior will continue to sell top drives and other products to third parties and will continue to service top drives owned by third parties.

Turning now to pressure pumping. Pressure pumping revenues increased 5.7% sequentially to $78.2 million in the third quarter from $74 million in the second quarter. This increase was primarily driven by increased product sales related to a shift in our work as the jobs on which we supplied proppant increased as a proportion of total activity.

Pressure pumping gross margin as a percentage of revenue decreased to 1.2% from 6% in the second quarter. Our lower margins in the third quarter were primarily attributable to higher-than-expected maintenance costs. As a result, we did not generate positive EBITDA in our pressure pumping segment.

Looking forward, relative to the third quarter, we expect an increase in pressure pumping activity. As such, our pressure pumping revenues are expected to increase approximately 15% during the fourth quarter. With this increase in activity and normalization of maintenance costs, we expect our pressure pumping gross margin as a percentage of revenues to moderately improve to 6%.

Our active fleets are now nearing full utilization. And we roughly estimate that with our current active equipment, our ability to further increase activity is now less than 15%. Recently, we have turned down a few jobs as we did not have equipment availability in the calendar.

We have not reactivated any spreads and still have 53% of the more than 1 million frac horsepower in our fleet stacked. We estimate it will cost us approximately $2 million to reactivate a spread. However, it has not made any sense to do so, as pricing remains at absolutely unsustainable levels.

While near-term opportunities to raise pricing remains somewhat limited, we are encouraged as we believe operators are starting to have to wait on high-quality crews. Based on forecasts for increasing activity at current commodity levels and the cost to reactivate idle pressure pumping equipment, we expect pricing to improve during the first half of 2017.

Before I turn the call back to Mark for his concluding remarks, let me provide an update on several other financial matters. With respect to CapEx, we expect to spend approximately $140 million during 2016, a decrease of $30 million from our previous estimate, which was predicated on a higher increase in activity.

The new full-year estimate suggests an increase in our year-to-date CapEx spend rate and is dependent upon upgrade and reactivation spending for drilling rigs. We expect depreciation expense will decrease approximately $6 million in the fourth quarter and by a similar amount per quarter during at least the first half of 2017.

SG&A during the fourth quarter is expected to be $17.5 million and includes approximately $1 million related to Warrior. We are currently projecting our effective tax rate to be approximately 36% in the third quarter.

With that, I will now turn the call back to Mark for his concluding remarks.

Thanks, Andy. From the lowest rig count on record, the increase in the industry rig count since May has been meaningful. Nonetheless, we believe the rig count recovery remains in its initial stages.

Notwithstanding recent increases in the demand for higher-spec rigs, the early increases in the rig count were driven by demand for smaller rigs. Even when considering the recent increase in demand for higher-spec rigs, smaller operators have driven the increase in the rig count to date.

Regardless of the catalyst that spurs greater activity from the larger operators, be it increasing confidence in the commodity prices, new budget approvals, or proving up acquired properties, we are optimistic that activity from these larger operators will trend higher. These operators, with their extensive well drilling inventories, stand to benefit economically from the efficiencies generated by the higher-spec rigs, and the utilization for this class of rig is already tightening.

More importantly, activity from the larger operators is expected to be much more service-intensive. Accordingly, this increase in drilling activity will drive pressure pumping demand and will go a long way towards tightening the market as industry supply continues to decrease through attrition and cannibalization.

Finally, let me take a moment to welcome the highly talented group of people from Warrior to the Patterson-UTI family. Innovative drilling technologies, be it introducing walking rigs to the lower 48 or the design of our latest fast-moving pad-capable rig design, the APEX-XK, has been an important (sic) to the transition of Patterson-UTI to the company we are today.

We believe that technology enhancements will continue to be important in drilling, whether it is drilling wells faster or more effectively drilling increasingly complex wells. With the many innovative technologies that the Warrior team has in their portfolio, we are very excited to have expanded our drilling technology position and our engineering capability.

With that, I'd like to both commend and thank the hard-working men and women who make up this Company. We appreciate your continuing efforts every day.

Also, I am pleased to announce today the Company declared a quarterly cash dividend on its common stock of $0.02 per share to be paid on December 22, 2016, to holders of record as of December 8, 2016.

Operator, we've now like to open the call for questions.

(Operator Instructions) Sean Meakim, JPMorgan.

On the pumping job mix, I was hoping to dig into that a little bit, if we could. You talked about the proppant delivery mix shifting in your revenue during the quarter. It would be great to hear an update on what that split looks like.

And are you getting traction on pass-through cost to customers at this stage? Just thinking about next year's expectation for price increases. Would you expect that to be a net increase in pricing or more just we have to start with some of the pass-throughs?

So first off, let's kind of start with the mix. And unfortunately, I'm not going to go into a lot of detail on that.

But what I can say is we just did see a shift in the mix of customers who provide their own sand versus customers that we provide sand for. As you know, when we are providing product, it's large volumes, but the margin is relatively thin on product.

In terms of pricing on product, today we're just not seeing increase in those costs. And so there's really no increase in the pass-through there in terms of what we need to uplift because we're just not seeing the increase in costs today.

Okay. Just thinking forward to 2017, your first half 2017, when you talk about trying to get pricing traction, do you think that that will be -- the margin would be tight enough to justify net pricing? Or you think we'd have to start with the supplies you need to get tight first?

I think that what we are seeing in the markets that we work in is that the supply of pressure pumping equipment -- active pressure pumping equipment is tightening. And with the rig count increases that we see, based on today's commodity prices, that's why we see activity in pressure pumping increasing, following the drilling activity. And why we think that pricing moves up in the first half in 2017 for pressure pumping. And we do mean service pricing in this particular case.

Got it. Okay. And then just one last follow-on to that, if I could. You guys have been very disciplined in terms of your strategy around reactivation. Others seem to signal that their target is to get in right before the price increases. So we are seeing reactivations elsewhere.

Just curious how you think about the risks to that, as more folks try to get through a pretty small door here into 2017.

One of the things that's happened here, certainly at the end of the quarter, is that we had to turn down a few jobs just because we couldn't work them into the calendar with the active equipment that we had. We probably could have activated a new spread and covered some of that work, but it just didn't make sense to do so right now. We'd like to see this market continue to tighten up with the active equipment that's available so that we can move the service pricing next year.

Okay, fair enough. Thanks, Andy. I appreciate it.

Marc Bianchi, Cowen.

First question on pumping, I suppose. Taking on more sand, you guys have some of your own sand capabilities and also capabilities in delivery that's a little bit different.

Is there an aspect where you think you have maybe a competitive advantage here to take the sand risk? Or how are you thinking about that?

I think our competitive advantage is just the scale that we have relative to companies that are smaller than us. We were managing almost 1 million horsepower at the peak in 2014. We never missed any work or any stages in 2014 for lack of ability to move sand to the well site.

We have railcars under lease. We own some of our own sand trucks. We have good contracts with mines across the US. And so we think we have a good ability both on the supply and the logistics side to move sand.

Marc, I would just add that I think it's somewhat underplayed oftentimes in this business to think about the service that companies like us provide and see it all as a commodity-type service. There are real skills and real know-how that differentiate some of us. And I think we are really pleased with the way our team has been able to differentiate itself in some of these respects.

Okay. Thanks for that, Mark. I think before you said that about 50% of your customers were sort of handling their own sand, or maybe I've got that wrong. Can you offer what that mix is now?

No, we don't go into the mix. But it's not that high.

Okay, great. And then maybe just shifting over to the drilling side, it sounds like things are getting better there in terms of the supply/demand balance.

Are you seeing the opportunity right now to contract rigs at a rate that compensates you for any of the upgrades that you are contemplating? And if not, when would you expect that?

Yes. We see with the discussions we are having with the customers, with some recent contracts that we've entered into -- which, by the way, we are trying to keep as short as possible right now -- we see the ability to recoup some of the costs for the upgrades that we are having to put on.

How long does that typically take?

For the costs?

For the recovery of the investment.

In busy times, we would like to get this back in a year and a half or so. So right now, it's over two years in terms of payback.

But I think the important part is that the market has moved to where -- in the early stages of this start of the recovery that we are moving into, it was just these highest-spec rigs that went to work, where now it's shifting to where we can start to charge for some of these upgrades.

Got it. Okay, thanks. I'll turn it back.

Angie Sedita, UBS.

I appreciate the color on the pressure pumping as far as your thoughts on pricing. And I guess I would ask one further is: do you still believe that Patterson needs to see roughly a 30% increase in pricing for you to unstack? Or has that changed? And any thoughts on given what you're seeing in pricing on when you could start to look at reactivating equipment?

We still think we need 20% to 30% improvement in order to activate a spread. As we mentioned, it's a $2 million cash cost between labor, OpEx, and CapEx to put these first few spreads back to work. So we think it's important to try to get that uplift.

It's -- as I mentioned, we could have activated a spread already to start to recover some of the excess work, but it would have been at today's pricing. And we just didn't think that was a good idea. And so we'd like to let the market tighten up, especially in Texas.

So would the thought be that you wouldn't look to reactivate equipment until potentially the second half? Or could that be in 2018 based on what you know today?

It would be based on when we have visibility of getting the price uplift.

Yes, okay, okay. And then appreciate any thoughts on the pricing side on the land side for high-spec rigs, number one. And then in industry-wide, how many rigs do you think could be upgraded to the specs that you outlined, with 7,500 psi, 7,500 -- pound -- ton -- mass and the AC walking capabilities, etc. So what do you think the industry's capability is to upgrade to those specs?

As we mentioned, we think there's about 300 out there right now that do meet that spec. It's actually a little bit difficult for us to estimate completely what we think that number is, but it could be in the 600 range. But I think the important part of that is that we think the market is starting to pay for these upgrades now.

And then thoughts on pricing outlook for those rigs?

I think pricing continues to go up as activity continues to climb.

Okay, great. Thanks. I'll turn it over.

Marshall Adkins, Raymond James.

The maintenance expenses in pressure pumping, they were a little higher than we thought. Was any of that reactivating stuff? Help me understand what those where that were probably higher than we all thought?

It really had more to do with some of the pricing agreements that we work under, where the operators can move our spreads within a basin. And in this particular case, we had a few spreads that were pumping higher-pressure jobs.

And so as you well know, with the higher-pressure jobs, we were consuming valve components and fluid ins a little bit higher rate. So it drove maintenance costs a little bit higher.

The challenge in today's environment is margins are so thin that it doesn't take much to tip the scale in the wrong direction on the maintenance side. But that's what happened to us with this quarter. We don't see that in the fourth quarter, and that's why we think that we get a moderate improvement in the margins going forward into the fourth quarter.

Perfect. All right, you mentioned you got a couple million per frac fleet to refurb. Early on, you got a few of those. Do you have much equipment just parked that's waiting on overhauls where you are going to spend $0.50, $0.60 on the dollar of newbuild to get it working again?

No. We don't see that with our fleet. As you know, we've continue to fund OpEx and CapEx for maintenance for our fleet. And so the spreads that we've stacked in this downturn require -- they require some work, but not anything at that magnitude.

What we've said all along is the first few spreads that go back to work will cost us about $2 million. That's labor, that's OpEx, that's CapEx. As we work into the fleet of stacked equipment, it kind of moves to $3 million and maybe $4 million at the tail end. So we don't get quite -- we don't get anywhere near that $0.50 on the dollar type number.

Perfect. Helpful. Last one from me. DUCs -- we've seen the rig count bounce up obviously in pressure pumping demand. But is much of the demand to the extent you can even tell over the last quarter and going forward related to the DUCs? Or give us some help there.

We still continue to frac some DUCs in the Northeast. We think there's some operators that are going to want to get some more fracs in before year-end as well. Don't have a good number for you in what that percentage is, but we're still fracking some DUCs.

Perfect. Thanks, guys.

Jim Wicklund, Credit Suisse.

I know it's a little granular, but when we look at your revenues and the rigs and all, we see that the implied spot rate, at least, has moved up over $1,000 from the bottom.

And first I guess want to ask is that right? And if it is, is this from contracted rigs rolling onto spot at a higher-than-normal spot because they want to keep their rigs? Or are you getting paid for the upgrades? Or am I seeing this right, and if it is, what's the reason?

I think you may be seeing the shift to lower number of rigs on standby. Our spot is still a range. It depends on the customer; it depends on the basin. It's one of the reasons why I prefer not to call it out. But I think that shift is really based on the rigs on standby going back to work.

How much do you get paid when a rig is on standby? Or how do you get paid? I'm just -- explain that process to me.

You know, when a rig goes on standby, the labor costs come out of the equation and we essentially get paid the margin on that rig that we would've made.

Okay. I appreciate that. And I agree with you on pressure pumping pricing returning in the first half of next year. There has been, of course, the Permian is the hottest basin on the planet. A lot of people we understand have moved equipment there. Can you talk a little bit about how you see the competitive landscape in the Permian for pressure pumping over the next year?

I think all the basins in the US are still very competitive just because of the overhanging equipment that's stacked. But we do see tightening in the markets that we work in.

So that's why we think that we are going to see continued tightening as rig count continues to move up. And that's why I believe that we'll see pricing in the markets move up in the first half of 2017. And certainly with rig count moving up in the Permian higher than other basins, it's going to tighten there before it tightens anywhere else.

Yes, that was my follow-up. So, okay. Thank you guys very much.

The important thought, Jim, going on would be that it's tightening in other markets also.

Yes, there's no question it's all going to get better in 2017. I'm hoping Marshall, your lips to God's ears. I hope he's right and I'm wrong.

Robin Shoemaker, KeyBanc.

Andy, wanted to ask since you've got these, I believe you said 32 rigs on term on average in 2017, 43 in the fourth quarter. So with those rigs that are on term next year, how do you feel about the possibility of early termination on those?

You mentioned that some of the standby rigs are going back to work. So I would imagine there's not much in the way of discussion or likelihood of early termination on those rigs on legacy high day rate contracts.

You know, if you follow our trend this year of early termination revenues per quarter, we were as high as $16 million and now we are down to $1.1 million in early term. So I think next year, we just don't see really any early termination. Of course, it's hard to predict what some operators may do, but that trend for us has been coming down.

Right. And you'll be throughout 2017 with the headwind of rigs term contracts expiring and those rigs going back to work at a spot-related rate. So the average rate comes down. Is the -- you didn't mention anything about 2018, but I assume many of these term contracts will conclude in 2018.

We have rigs that work into 2018, correct. Under term [markup].

Right, okay. And just a broader question on both pressure pumping and drilling. Is the increase in your activity, either on the rig side or the pressure pumping side, likely to come from your existing customer base? And with -- or are you seeing a much broader set of opportunities? Just around that issue if you could comment.

One of the things that we've always enjoyed here at Patterson-UTI is I believe we have one of the broadest bases of customers in the industry. If you look at the number of operators that we were working for in 2013 and 2014, the list was a very long.

And so from that base of customers, we're going to work for some of these customers again in 2017 and 2018. But I think that we will also pick up some new customers at the same time, just because of the quality of the services, the new technology that we are providing. Not just the APEX-XK, but things that we'll do to enhance rigs in the future. And then the high service quality of our pressure pumping fleets.

Okay, good. Thank you, Andy.

Michael LaMotte, Guggenheim.

Andy, the topic of super laterals has come up a bunch on services calls this quarter. And I know that rig efficiency and reducing the number of days to drill has been a trend that we've been dealing with for many years now.

I'm wondering if that begins to reverse now with super laterals. And are you on location longer? And if so, is it linear with the amount of footage that you're drilled or is the horizontal complexity actually -- I guess where I'm going is is this becoming a multiplier effect potentially to ultimately to rig demand?

So I think that -- and it's a multipart answer to your question. I think several things. Yes, we are seeing the longer laterals. It's one of the reasons that we began looking at Warrior, for instance, for the higher-torque top drives, to be up to manage that.

It's one of the reasons that we get the request for the 7,500-psi systems and upgrading the rigs, which we now getting to move the pricing for. Also, sometimes the third pumps.

So we are doing things to be more efficient at the same time on these longer laterals. Yes, it's going to take more time to drill. It's just more footage. But we are doing things to be more efficient and minimize the risk for the operator, and I believe we are starting to get paid for these things. So that's one aspect of it.

But as rig count continues to increase, as we move into 2017, we are going to see more operators start to drill at the same time. So if you look at efficiency in general across all the basins, you could see efficiency reverse from what we did in 2015 and 2016 just because so many more operators will begin to drill again.

Yes. Like you said, a lot of moving pieces. But generally, the trend it doesn't feel like it's getting -- it feels like efficiency has sort of run its course, I guess.

Certainly I think we were seeing higher efficiencies than normal in 2016 just because we were down to some of the best operators, some of the best rigs, some of the best pressure pumping crews in the best areas of the geology.

Yes. And you mentioned that in West Texas, you were 100% utilized on your super ACs. What about in the other regions? And you talked about sort of recouping cost to upgrade. Any mobilizations and recouping costs to maybe moving rigs into West Texas?

We don't see a lot of rig movement right now. If we did move rigs, we certainly would get compensated for the mobilization. But we think that the rig count in general continues to climb, and so we think that we will be putting rigs back to work in most basins.

Okay, great. Thanks so much.

Waqar Syed, Goldman Sachs.

Thank you. Andy, on the pressure pumping side, I noticed that the revenue per job was down by about 7% or so, even though you said that there was a mix shift towards more sand going through your P&L. So are you seeing a net -- you continue to see net pricing declines in the third quarter or is there something else that I'm missing?

I think it has to do with a change in the stage count per job as well for some of the customers that we pump for. We may have pumped less stages per job. And that's why you see that change in the mix on revenue per job. But I don't think in terms of revenue per stage we saw necessarily a decrease.

You know, our biggest challenge was the maintenance costs that we had. And that's what really drove our margin challenges in the third quarter. But when it comes to what we can charge per stage in terms of service costs, I believe that we'll start to see that go up across the industry in 2017.

Good. And secondly, just on accounting for Warrior, are you going to report that as a separate business line? Or is it going to be reported within the drilling division?

Waqar, this is John. At this time, it's going to be reported actually in with corporate. And as the business grows, we'll probably move it out to be its own segment. But at this point, it's just a little too small for that.

Okay, great. Thank you very much.

Scott Gruber, Citibank Group (sic).

Mark, when we've spoken in the past, you mentioned that you'd be disappointed if you weren't able to find a way to take advantage of the downcycle. And here in the third quarter, you made a nice acquisition with Warrior. Does that satisfy your appetite to expand the portfolio during the downturn or does the search continue?

Quite frankly, we are always on the lookout for good opportunities. And we were obviously delighted that the Warrior acquisition became available.

Quite frankly, we don't think we would've had that opportunity to acquire a company with all of the portfolio -- patent portfolio and other technology attributes that Warrior has in a different kind of market. So this was exactly the sort of thing that we kind of hoped for and very much desire.

Frankly, we've been building this Company for more than 20 years and much of this team, including myself. And we are always on the lookout for good opportunities. And so I guess my attitude is that in 20 years, I've never been satisfied and don't expect to become satisfied anytime soon.

Do you have a preference for equipment? Additional services? Is there an angle you are searching for currently?

I'd like to think that we have the sort of views that Warren Buffett has often spoken about is you find good people with good companies and good assets and you hope to acquire them for a fair price. That's what Warrior was for us.

And then Andy, with regard to Warrior, you mentioned the higher torque top drives as being a motivating factor in the purchase. Are customers demanding the higher torque top drives as part of the upgrades currently?

I wouldn't say it's a demand yet, but we are just trying to prepare our technology position for where we think it's going. We are starting to see longer laterals. Not everybody is drilling them; a few operators are. But we just want to be in the right position when that trend continues.

Got it. And then turning to pumping, other pumpers have discussed the expansion of the size of their pumping fleets on location, given both job requirements and the need for more backup. Andy, have you witnessed that trend within your own fleet? And if so, is it evident across both Texas and Appalachia?

For us, I wouldn't say that's any kind of change or change in a trend. For us, we continue to fund maintenance OpEx, maintenance CapEx. So for a similar sized job, we are not bringing any more pumps than we would have a year ago or two years ago.

So the job requirements haven't dictated more pumps?

Not for us, necessarily. We are pumping for the most part some higher volumes, some higher sand volumes per well. But it's pretty much the same number of pumps pumping the job.

We've heard of other companies that have brought additional equipment to the site on account of concerns about reliability. Given the way we've maintained our fleet, we haven't had to do that for our customers.

Got it. So where does the average size of your fleet today stand in terms of horsepower and location?

It's in that 40,000-horsepower range depending on the job.

Okay, thank you.

Kurt Hallead, RBC.

This is Ben on for Kurt. Just quick question. On the rig count for the fourth quarter, we have the rig count tracking double digits up quarter over quarter. How come Patterson's rig count might lag that?

I'll give you a little bit of color on what we are seeing. We said we're going to move up to an average of 63. But what our exit is -- sorry; average of 65. But our exit point towards the end of December is likely 70 rigs in the US, 2 rigs in Canada for a total of 72 rigs. So that's how we see it. And we see rig count continuing to go up into early 2017.

Okay, that's helpful. Appreciate that. Then on the frac pricing, on the kind of pricing you guys gave to activate fleets, could you give some color on where that is on an EBITDA basis or relative to the cost of capital? And then maybe where that would put pricing relative to the prior-cycle high?

You asked a lot of moving part questions there. But as I stated, it's about $2 million, and that's labor, OpEx, and CapEx. The majority of that is actually labor.

And so we certainly need to get a price increase for it to make sense for us to reactivate these spreads and really just cover the costs in general, not just the cost of capital. I wouldn't say -- there's not a high percentage of that number that's really capital cost.

Okay, that's helpful. I'll turn it back. Thanks.

Timna Tanners, Bank of America.

Wanted to ask if you could follow up on something we talked about last conference call regarding competitor behavior. And if you could talk about if that has improved with some pricing below cash breakeven levels.

Certainly in pressure pumping, with the number of pressure pumping companies out there, it's our view that there are a number of companies that are still working at negative cash flow. And we are doing our best to stay at least breakeven or slightly positive cash.

We weren't successful in the third quarter because of the higher maintenance costs that really drove that for us. But we expect that to improve going forward into the fourth quarter for ourselves.

But I think in general, I think our competitors have the opportunity to improve their pricing in 2017 because I think that because of the increased drilling activity and the way we look at how that rolls into pressure pumping activity that the market in general will be able to raise pricing in the first half of 2017.

Okay. Can you comment on the rig set? I know you commented that you are in -- recently also about some players there that weren't as economically-minded.

On the rig side, I think everybody, certainly in high-spec rigs, has been cash positive. And so in terms of pricing, that's been a better market.

I think we've seen some of our competitors who were at lower utilization than ourselves that needed to catch up on utilization. But in general, like I've said, I think that pricing on high-spec rigs continues to go up as activity improves.

Okay. And then along those lines, just wanted to see if you have any further detail you could provide regarding competitor -- customer appetite for longer-term contracts. And I know you mentioned that you weren't inclined to extend longer-term contracts unless pricing improved.

So what are your customers saying about longer-term contracts? And is there a price or a margin where you start to think about offering them?

The contracts we've recently signed for rigs have been six months. And so we are just not getting pushed to longer-term contracts right now.

Okay, great. Thanks.

Jeffrey Campbell, Tuohy Brothers.

You mentioned the costs to upgrade circulation and walking on the rigs. I was just wondering how long does it take to affect these upgrades once you've determined to make the investment?

The timing for the upgrade is really about having the long-lead items ordered. And so we stay in front of that in terms of inventory and working with the suppliers. So if you don't have those items moving in your direction or in your inventory, then it could take months to have all that ready.

When it's time to actually put it on the rigs, it's roughly a week to 10 days. So it's something that can be done before a rig goes out. It can be done between wells, between moving from pad to pad. So the time to actually do it is not that long once you have the inventory items, which we do.

Okay, great. That's helpful. You forecast fewer rigs on term in 2017 than in the present. I was just wondering: is that more reflective of customer reluctance to take on time commitments? Or is it more on the Patterson side not wanting to tie up rigs at current day rates?

I think it's more on our side. We think there is upside in pricing in 2017 and we're going to try to keep rigs on as short a term as possible. But at the same time, we're not being pushed. So a customer might mention it, but at the end of the day, we've only signed really six-month contracts.

Okay. And finally, I'd like to ask a Warrior question. You've talked about an extensive patent portfolio and other attractive technologies besides the top drives and the pipe handling that you called out as the kind of main motivator.

Could you just give a little color about some of these other technologies that you are excited about? And you think they might be able to attract capital in 2017 or beyond?

I think just to give a little bit more information on the top drive system and the some of the pipe handling, Warrior has a great design on the top drives that incorporates a lower end that can be controlled separately from the upper end. And I know that's in the weeds, but what it means is that we can use that lower end of the top drive to run casing. We don't have to bring extra equipment out to run casing.

And with a makeup tong design that they have that goes on the rig floor, we can make up both drill pipe and casing. So we are going to have the ability going forward as we begin to slowly deploy this technology into our own fleet that we will be able to run casing on our rigs without bringing extra equipment out. So that's just one example of where we think their technology is interesting.

Okay, great. Thank you.

Chase Mulvehill, Wolfe Research.

So Andy, I guess it looks like the cash margins this quarter -- or sorry, guidance for fourth quarter is about $7,500. Can we talk about the progression of cash margins as we kind of walk through 2017? Do we expect them to kind of continue to step down about $1,000 a day? And kind of where do you see the bottom?

I don't believe we'll get into a discussion on what we see in terms of that level of detail for 2017. I think the good news is for us that the rig count continues to go up at given today's commodity prices. And that we think that the market pricing moves up as well at the same time.

So even though we have rigs rolling off of term contracts, we believe that the contracts that we'll sign or the agreements to drill wells, that those day rates will move up as well.

Okay. Maybe this might help us. What's the delta -- what's the difference between the term average day rate and the spot day rate you are realizing?

We don't call that out because I don't want to call out the spot day rate. We work for various customers in various basins and it's really a range.

Okay, all right. Do I get to keep going until I get an answer? (laughter)

If you've got another one, sure.

Okay. I guess if we think about -- I heard you guys talk about supplying less sand on jobs during the quarter. Was that right? Sorry; I was going back and forth.

We supplied more sand during the quarter. And sand --

Yes, on an absolute basis. But on the number of jobs that you supply, you know, sand on a percentage basis?

On a percentage basis, we supplied more sand in the third quarter. And products are just at a very thin margin.

Okay, all right. So it doesn't seem like you are maybe -- I was going to ask if you are seeing any trends about E&Ps kind of sourcing their own sand.

No. We are not seeing any change in E&Ps who source sand versus E&Ps who don't.

Okay. All right, last one. Could you talk about the monthly revenue progression for pressure pumping? And then kind of what September margins look like?

No, we don't get into the monthly details.

All right, I tried. One for four is not bad. Thanks.

Jason Wangler, Wunderlich.

Most of my questions have been answered. It was a maintenance question. I think you mentioned in your prepared remarks, the depreciation down about $6 million a quarter through first half. Is that right?

That's correct.

Okay, thank you. I'll turn it back.

James West, Evercore.

I was just saying this is Alex on for James. My first question is do you guys see yourselves and other competitors upgrading rigs serving to cap any pricing traction on the super spec category?

No. We see that we are doing some upgrades, we see competitors doing upgrades. But because of the increasing demand, we are seeing that we are able to get paid for those upgrades going forward. And I believe that as the rig count continues to go up in fourth quarter and into 2017 that overall market pricing for high-spec rigs continues to climb as well.

Okay. And have you guys incurred any, I guess, engineering difficulties with swapping out substructures to walking substructures?

No, it's not a complete swap on the substructure. And some of the substructures we have are designed to accept the walking systems. But we also have walking systems designed that can be added to any substructure. It's not a change of the sub; it's just a component that goes below the sub.

Okay. My second question, slightly more abstract. And I appreciate commentary earlier on efficiencies potentially slightly reversing next year as the crews that are added are less efficient than the ones we have now.

But drilling days are still down significantly from the peak in 2012, 2011. Do you see a need to shift away from a revenue-per-day business model to something more performance-based or turnkey, say, over the next 5, 10 years?

First off, as we continue to put out rigs, I don't believe that our crews work any less efficient than the crews that are currently working. But not all operators are as efficient and not all operators have some of the easier geology. And some of the operators that are currently working today will end up putting rigs in parts of their landholdings that are just higher risk to drill.

And that's what you see when you have a large number of rigs working. And that's why I think the overall efficiency for the industry could reverse from the exceptionally high efficiency we saw in 2016. So that's really kind of how I see the efficiency part working.

I'm sorry. What was the other part of your question?

I was just remarking that it's days per well is still down from the previous cycle peak. And do you see a need to shift away from a revenue-per-day model over, say, the next 5, 10 years?

The challenge with shifting from a revenue-per-day model on a large capital asset like a drilling rig in the way the industry operates today is that first off, we've got to recover the cost of the capital that we've invested. And so we have to work at some sort of at least base-day-rate model that allows us to recoup that capital, which doesn't exist today, but I believe that pricing continues to improve as rig count continues to go up in 2017.

But performance is difficult because we don't control all the aspects of the operations. We don't choose the bits. We don't pick the mud systems. We don't control the directional drilling operations.

And there's so many things that happen in terms of -- we don't do the casing designs. And so there's too many things that are in the operator's control that makes it difficult for us to enter into performance agreements.

Okay, understood. Thank you, gentlemen.

John Daniel, Simmons & Company.

Thank you for taking the call. If you look at current quoting activity today for your rig business, what percent of those quotes do not require either a walking rig or a 7,500-psi system?

I can't tell you all the quotes that are coming out of our marketing team right now, but it's going to be very, very small percentage.

Very small. Okay. For the rigs that just need the 7,500-psi system upgrade, do you have either enough of the long-lead time items today or the ability to get all of those items such that you could upgrade all of those rigs in 2017?

Today we don't see any constraints in getting the components that we need to do 7,500-psi upgrades. We continually work with the various suppliers that we have, but it's how we are managing it that's important, too.

So we are only upgrading to stay ahead of the pace of the rigs that we are putting out. So our intent is not to just go in and wholesale upgrade the fleet right now.

I just want to make sure if that need was -- if it arose that you could do it.

We believe we can. Based on our forecast in the next year, we believe that our suppliers can manage it.

All right. This is not meant to be a snooty question, but I'm going to try anyways. You guys have previously noted an intent to not redeploy stacked equipment until pricing goes higher.

Applying that same discipline to your current working fleet and given that the costs incurred on higher-pressure jobs this quarter, will you continue to accept higher-pressure work if you don't get pricing increases?

Yes. What happened in the third quarter was the agreements that we have with the customers allowed them to move into certain parts of their basin where we pump some higher-pressure jobs. And it happened on more than one occasion.

And that's why we see a modest improvement in margins in the fourth quarter. We see a little bit stronger activity, but we don't anticipate pumping those types of jobs.

Overall, as we move forward into 2017, I believe that we are going to see service pricing across the industry improve in the first half of 2017. And I believe that we'll have the ability to better control the pricing on those types of jobs at that time.

Okay. Are you seeing any type of trend, Andy, that would suggest that the industry is going to have more higher-pressure type work, which could therefore restrain the margin improvement, notwithstanding pricing going up?

No, we are not seeing it as a trend. It's really operator-dependent and depending on their landholdings. But I don't see it as a trend.

Thank you. 100% hit rate good; I feel good. Thanks, guys.

Brad Handler, Jesse (sic - Jefferies).

Thanks for squeezing me in. I think I just have two. And the first is I guess -- I know it's a vague in the way that a number of the questions wind up being a little vague.

But your growth in the third quarter in pressure pumping is slower than the growth you expect for the fourth quarter. And you are working with the same set of available equipment.

And I guess I'm just curious. You talked about turning away some work because of pricing. Presumably the mix of opportunities in the fourth quarter got a little better so that you would expect to fill the -- you are able to fill the calendar. Is that fair to assume?

Remember, in the third quarter as well, we also had a shift in the customers that we delivered proppant to versus customers that had their own proppant. So we had the increased revenue in the third quarter from that.

That shift changes back a little bit. Activity goes up a little bit. And we think we'll have maintenance costs more in line with normal maintenance costs for the quarter and the fourth.

All right. But I'm sorry, but Andy, if it's less proppant per job, then the revenue number goes down. Again, it just seems like you've gotten -- did the landscape change in some way relative to customers that you are intent on serving such that the opportunities set rose?

Yes, but activity goes up a bit as well.

Right. I suppose what I'm trying to get at is in a sense, why? Like, what is it about the activity landscape that got a little better in the fourth quarter since pricing didn't? What's the priority set that works for you?

It's just the amount of activity that's available in the industry and the way that we can work it in the calendar.

It really is turns on which customers -- and which customers and what basins under what circumstances. And there's so many moving parts that answering the question the way you're asking is very difficult.

It's hard to do, okay. Let me try a slightly different one that's pretty quick, probably. I don't think I've heard the word holiday in this call. I may have missed it.

But to what extent do you feel like the holiday season might be elongated, might be short, might be -- the intensity of demand implied by the word holiday?

I think the fourth quarter can always have some typical seasonality risks. But we think that we've worked that into the projections that we provided to you.

And I would just add that one of the questions earlier concerned the rate of increase of rigs. And our rate of increase in rigs took into account the fact that we are aware of the fourth-quarter seasonality and kind of factored that in. And so that's part of the reason we gave the number we gave. Could it be better --?

I appreciate -- I guess I appreciate that. I'm just curious of you had to guess, would the holiday affect be a month long or a week long? This year?

Don't think we have any visibility.

Right. Okay. Thank you, guys. I'll turn it back.

Marc Bianchi, Cowen.

Okay, thank you. Just real quick following up on Brad's question about holidays. If there weren't any holiday impact for the pumping business, what would the revenues be up compared to the 15% guidance?

You know, I don't have a good number for you. But it's not just holidays. It's seasonality and the impact of winter weather in the Northeast. So there's just too many variables there.

But like I said, we think we have a reasonable number based on what we think is going to happen based on customers' discussions and their schedules, where we've already slotted many of these customers in on the calendar and allowing for the weather seasonality that can occur in the fourth quarter as well.

Got it, okay. Thanks, Andy. And then just on the drilling side, I've heard a lot of comments about sort of a positive forward view on pricing. Have you seen any improvement in the pricing currently? Have you put contracts in place that are at better prices than what you had previously?

We are starting to see some small increases; not enough to get us excited for the fourth quarter. But I believe that with the increasing activity on drilling side that that's going to drive increased activity on pressure pumping. And that's why I believe that the market in general will see higher pricing in pressure pumping in the first half of 2017 sometime.

Okay. But my question was specifically on drilling. Have you seen any improvement on the contracts for drilling?

We have in terms of the fact that we've had this shift from where when we talk about the rigs that are fully loaded with all the specifications that we've discussed, in the early part of getting in the initial stages of this recovery, those were the rigs that worked. And now we are getting to the point where we can start to get paid for making those improvements on those rigs.

Okay, very good. Thank you. I'll turn it back.

Thank you. At this time, I'm showing no further questions in the queue. I would like to turn the call back over to Mark Siegel for closing remarks.

I'd just like to thank everybody who participated in the call and all who listened. And tell you that we look forward to speaking with you in February of next year when we report our fourth-quarter earnings. Thanks, everybody, for their participation in the third-quarter 2016 earnings conference call. Thanks.

Ladies and gentlemen, thank you for your participation in today's conference. This does conclude the program and you may now disconnect. Everyone have a great day.