Patterson-UTI Energy, Inc. (PTEN) Q2 2016 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen. And thank you for standing by. Welcome to the Patterson-UTI Energy Incorporated Second 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 call is being recorded. I would now like to turn the call over to Mr. Mike Drickamer. Sir, please begin.

Thank you, Howard. Good morning, and on behalf of Patterson-UTI Energy, I’d like to welcome you to today’s conference call to discuss results of the three and six months ended June 30, 2016. Participating on 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 U.S. Private Securities and Litigation Reform Act of 1995, and 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’s my pleasure to turn the call over to Mark Siegel for some opening remarks. Mark?

Thanks, Mike. Good morning and welcome to Patterson-UTI’s conference call for the second 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 June 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 second quarter, as set forth in our earnings press release issued this morning, we reported a net loss of $85.9 million or $0.58 per share on revenues of $194 million. Total adjusted EBITDA during the second quarter was $46.7 million, and we remained EBITDA-positive in all three of our business lines. Our financial position remains strong, and we recently amended our bank credit agreement to, among other things, extend the maturity date of our unsecured revolving credit facility. The capacity under our revolving credit facility, subject to a borrowing base, remains at $500 million through September 30, 2017, after which current commitments of $357.9 million have been extended for 18 months to March 2019. Additionally, we repaid the entirety of our $230 million in bank term loans outstanding at June 30, utilizing cash on hand and $70 million from our revolving credit facility. After repaying these term loans, our pro forma debt to capitalization at June 30 was reduced to 22%, and we now do not have any term debt maturities until October 2020. As mentioned, availability under our unsecured revolving credit facility is now subject to a borrowing base which we expect will be approximately $360 million when determined as of July 31, 2016. This borrowing base is comprised of eligible equipment, receivables, inventory, and unencumbered cash. Our borrowing base is designed to grow with working capital and is expected to provide us with ample liquidity in the recovery. We are very pleased with this extension and we appreciate the confidence in our company shown by our lenders. With that I will turn the call over to Andy.

Thanks, Mark. In contract drilling, our rig count during the second quarter averaged 55 rigs in the U.S. and less than one rig in Canada, compared to 71 rigs in the U.S. and three rigs in Canada during the first quarter. Activity levels stabilized for both our drilling and pressure pumping businesses during the second quarter. Since reaching a low in late April of 52 rigs, our U.S. rig count has improved to 58. For the month of July, we expect our rig count will average 56 rigs in the U.S. and two rigs in Canada. During the second quarter, total contract drilling revenues were $115 million including $5.4 million of revenues from early contract terminations. These early contract terminations positively impacted our average rig revenue per day of $23,070 by $1,080. Excluding early termination revenues, average rig revenue per day during the second quarter would have been $21,980 compared to $22,820 in the first quarter. Total average rig operating costs per day during the second quarter increased to $12,770 from $12,150 in the first quarter. Costs associated with preparing rigs for reactivation contributed to this increase. Total average rig margin per day during the first quarter was $10,290. Excluding the positive impact from early termination revenues, total average rig margin per day during the second quarter was $9,210 compared to $10,660 during the first quarter. At June 30, we had term contracts for drilling rigs providing for $507 million of future day rate drilling revenue. With the recent reactivation of rigs, we have entered into a few six-month contracts. Based on contracts currently in place, we expect an average of 45 rigs operating under term contracts during the third quarter, and an average of 42 rigs operating under term contracts during the second half of 2016. Looking forward, assuming crude oil prices remain at or above recent levels, we believe U.S. rig counts will continue to increase. During the third quarter we expect our rig count will average 60 rigs in the U.S., a 9% increase from the average for the second quarter. In Canada, the rig count has improved but remains well below year ago levels. During the third quarter we expect our Canadian rig count will average two rigs, up from less than one rig during the second quarter. The increase in our rig count is expected to reduce our average rig revenue per day due to a decreasing proportion of rigs working on higher day rate legacy term contracts, partially offset by a smaller proportion of rigs on standby rates. Considering all of the moving pieces for the third quarter, we expect average rig revenue per day excluding early termination revenues, to be $21,650. Similarly, there are moving pieces that will affect average rig operating costs per day in the third quarter. A smaller proportion of rigs on standby, and reactivation costs, will have the impact of increasing costs. As such, we expect average rig operating costs per day in the third quarter of approximately 13,200. The recovery in our rig count seen thus far has been oil-driven and focused on our APEX rigs in west Texas. As expected, customers are looking for high-spec pad-capable 1500-horsepower rigs that have a 7500 PSI circulating system and 750,000-pound mass capacity. We believe the number of available pad-capable rigs with these upgrades is limited, and we estimated there are only approximately 250 across the U.S. Utilization for these rigs is expected to tighten quickly as the industry rig count continues to increase. We believe this is positive for high-spec contract drilling. Within our own fleet we have seen utilization tighten for these rigs as we have 49 APEX rigs with these specifications, of which 42 are currently contracted or 86% utilization. As well, we have an additional 79 1500- horsepower APEX rigs that can be upgraded. Turning now to pressure pumping. Similar to drilling, pressure pumping activity levels stabilized during the second quarter. We are beginning to see some increases in activity in the oil basins in which we operate, but activity in the natural gas basins remains soft. I would also like to mention that in the northeast gas basins, an increasing proportion of our recent work has been related to completing wells that were previously drilled but uncompleted, commonly referred to as ducts. Pressure pumping revenues during the second quarter were $74 million compared to $96.3 million in the first quarter. Gross margin as a percentage of revenues decreased during the second quarter to 6% from 8.8% in the first quarter. We continue to generate positive adjusted EBITDA from pressure pumping during the second quarter. Pressure pumping pricing in all basins remains unsustainably low. In this low price environment, we continue to be disciplined in the use of our assets. Our focus continues to be on margins rather than market share, and so we have not activated idle spreads and we have approximately 53% of our horsepower stacked. Our active horsepower continues to focus on 24-hour operations with more than 90% of our fracturing revenue during the second quarter coming from 24-hour operations. However not all of our equipment ends up working a full months, which leaves us with open space on the calendar. In filling this open space, we believe with our current active equipment, activity levels could improve by 25% or more. While activity is improving in the oil basins in which we operate, pricing remains unsustainably low. We continue to be focused on margins over market share and we believe we are capturing our share of the available cash-positive work. For the third quarter we expect our activity levels will be relatively flat. As such we expect that our revenues and margins will also be relatively flat with the second quarter. In both of our core businesses, drilling and pressure pumping, we undertook a careful process to stack equipment during the downturn, which leaves 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. So far, we have been able to meet our hiring needs for planned rig reactivations. However, given the duration of the downturn, we expect the oilfield service industry will have challenges to meaningfully increase the number of personnel quickly in a recovery. 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 $170 million during 2016. We expect depreciation expense will decrease approximately $6 million per quarter in each of the third and fourth quarters of 2016. SG&A during the third quarter is expected to be $18 million. We are currently projecting our effective tax rate to be approximately 36% in the third quarter. We do not expect to pay meaningful cash taxes during 2016. With that I will now turn the call back to Mark for his concluding remarks.

Thanks, Andy. Activity levels stabilized during the second quarter, and we were encouraged by the recent increase in our rig count. During the recovery we believe we are well positioned to benefit given our high-quality equipment and the strength of our balance sheet. We have 161 APEX rigs within our fleet and 1 million horsepower of modern frac equipment, both of which are more than we had at the peak in 2014. During the downturn in both drilling and pressure pumping we have funded maintenance expenses and undertook a careful process when we stacked equipment, so as to be well prepared to reactivate equipment. Just as importantly, we maintained our financial flexibility so that we are well positioned to cover reactivation costs and increases in working capital. Overall, I am pleased that we were able to maintain our high level of operational execution during what has been the worst downturn since the mid-’80s, and that we are well positioned to benefit from a recovery. With that, I would like to both commend and thank the hard-working men and women who make up this company. And we appreciate your continuing efforts during this challenging market environment. Also, I am pleased to announce today that the company declared a quarterly cash dividend on its common stock of $0.02 per share, to be paid on September 22, 2016 to holders of record as September 8, 2016. Operator, we’d now like to open the call for questions.

Hey, good morning.

Good morning.

So you talked about the rigs that you’re putting back to work. You know, highlighting that the high-spec ones are getting the strongest uptake. But if you could maybe give us a little more sense of the mix, perhaps something like, you know, contracted versus spot, or some of the terms look like, or customers. A little more underlying sense of what’s happening with those rigs that are getting put back to work.

So the rigs that are going back to work, as I mentioned, a few of those rigs we signed up some 6-month term contracts. We’re very careful in this process. We don’t want to sign up, you know, rigs for term contracts for any longer than we think, because we think we have upside. So, you know, we’re very careful in that process and we’re careful in the negotiations with the customers today. So, there’s ongoing discussions with operators. And so I don’t want to get into too many details about exactly, you know, how we’re doing this or what we’re doing.

It’s quite a different market than the last downturn, but I guess is there any difference in how you’re approaching it? Is your strategy different in terms of spot versus contract versus the prior downturn?

You know, when we have these downturns, the playbook looks very similar. We have to control the costs and we have to scale the business, you know, as we work our way through this downturn. And then when we get into this period where we’re reactivating equipment as we’re doing in drilling right now, then we have to reverse those processes but we reverse them carefully so that the costs don’t balloon and get out of control. So we’re carefully bringing back the number of people we need. We’re very careful about how we spend money when we reactivate the rigs. And we just take this part of the recovery that we’re in so far in terms of rig reactivation, you know, one step at a time.

And thank you for that. Then it’s fair to say, I guess, the recent move in the commodity price has been fairly quick. Would you say that customers are, you know, more focused on the rate of change as much better versus 2Q versus 1Q. Is that where you expect to kind of flow through into activity this quarter or if there, you know, continue to risk to the quarter if we stay at commodity prices, you know, closer to 40 than 50?

You know, the best view that we have of that right now is just based on the recent commodity prices. And, you know, we’re still seeing the – you know, our projection is for a 9% increase in our average rig count quarter on quarter.

Okay. Fair enough. Thank you.

Thank you. Our next question or comment comes from the line of Brian Uhlmer from GMP Securities. Your line is open.

Thank you, and good morning.

Good morning, Brian.

I had a quick question on my math here. The OpEx per day, about $600 increase. You said the reactivation contributed to that. Is that the sole cause of that? Or is it some percentage of that?

You know, as we said, there’s a lot of moving parts in there. You know, we had the costs associated with the rig reactivations. There’s a few other things I can explain as well. We had a decrease in activity in Canada, so that impacts the overall cost per day from the decrease up there. We had a reduction in activity, you know, to begin with in the quarter that provided for lower fixed cost absorption. And then some of this was partially offset with an increase in the proportion of rigs on standby in the second quarter relative to the first quarter. So there were just a lot of different moving parts in there.

Okay. So in general, moving forward as we model this out, what’s a good number to use? Because, you know, if I use the 600, it equates to about $0.5 million per rig which seems way too high. What’s a good number to use as a reactivation cost, number one. And number two, can we assume that your average daily OpEx cash basis at the rig, not with burdens and et cetera, will be equal to the other rigs that are currently out in the field? Or is there any type of uplift in costs after you get it out to the field?

Okay, I’m going to take your question in a few parts here. So, you know, as we reactivate rigs, you know, on a per-rig basis, you know, we have costs in the range of, you know, up to $200,000, just looking at the costs to reactivate a rig. You know, we have labor costs included in that. We have some, you know, expenses just to get things going again. And so those numbers work into those reactivation costs. But once the rig is back in the field, it’s, you know, in a steady state mode once it’s working, it doesn’t have any additional costs other than the normal, you know, OpEx and CapEx costs for running the rig, if that helps you.

Oh, that’s exactly what I wanted to hear. And then we spread the burdens over more rigs, so the average daily OpEx for the fleet will go down. Is that – Absent the cost of the reactivation?

Correct.

Okay. So the pay back on a reactivation is and the costs associated with a reactivation, you would say, is two to three months or less. Is that the correct way to look at it?

It depends on how you’re modelling the EBITDA produced out of that, but it’s probably not too far off.

Okay. Excellent. That was my way of backing into your average daily margin without you answering it, because I knew you wouldn’t. That’s really all I had. I’ll turn it over. Thanks a lot, gentlemen.

Thanks.

Thank you. Our next question or comment comes from the line of James West from Evercore ISI. Your line is open.

Hey, good morning, guys.

Good morning, James.

Andy, you talked about your pad-capable rigs, 250 in the U.S. pretty well utilized. On these pad-capable rigs, how many of those would you say have walking systems? Or is that are all those walking systems? And then with respect to the mud pumps – I know that’s a big part of it, the 750 PSI – or the 700 PSI mud pumps. How many mud pumps are on these rigs? Is it three? And are we adding backups at this point?

So, you know, when we look at this breakdown, you know, and we count, you know, roughly 250 rigs that have all these specifications that I mentioned, so these are 1500-horsepower pad-capable rigs, we’re including, you know, the best view of the count that we have across all the drilling contractors, so you have a mix of walking rigs and skidding rigs, you know, across the contractors there. And in terms of 7500 PSI, it’s really the pressure rating on the piping and the fluids into the pumps, and for the most part, you know, these are rigs with just two pumps. You know, we’re in some discussions with customers to add a third, but the majority are still working two pumps.

Okay. And do you see the addition of a third pump as a trend that’s happening that will probably increase going forward? Or is this just more one-offs?

I would say that, you know, based on the number of discussions we’re in on third pumps, it’s not a large trend yet.

Okay. Fair enough. And then just a final one from me, on term contracts right now – I mean, obviously you could get term at current rates, which you don’t want, but are there opportunities to lock in rigs with inflation factors, day rate inflation factors in them, for longer than six months?

You know, we haven’t really seen that type of opportunity yet. As I mentioned, we signed a few 6-month contracts, just to try to keep the terms relatively short. And these were around 6-month drilling programs, so it worked for both parties. You know, and in terms of, you know, working on an agreement that has an escalation, that’s always challenging and we just haven’t seen it yet.

Okay. Got it. Thanks, Andy.

Thanks.

Thank you. Our next question or comment comes from the line of Marc Bianchi from Cowen and company. Your line is open. Okay, I will turn into the queue. Our next question or comment comes from the line of Brad Handler from Jefferies. Your line is open.

Thanks and good morning guys.

Good morning.

I guess a couple of philosophical questions please as it relates to reactivating rigs and thresholds to do that. The – how much – 6-month contract enough at this point? You have enough confidence in continued rig count recovery so that that’s kind of a target framework within – and obviously current market pricing?

Well, you know, the starting point is the pricing on rigs today for high-spec rigs and especially with the specifications I’ve listed, you know, we were not pushed to cash break-even in the operation of these rigs. You know, we were still positive cash, you know, and the rings were working. So we still, you know, it gave us opportunity to put more rigs back to work, get some of our people back to work and still be cash-positive with a relatively short payback on the additional costs, you know, to activate and reactivate these rigs. So, you know, we certainly want to, you know, meet our customers’ needs and we certainly want to have the opportunity, you know, to make these sound economic decisions to put these rigs back to work. In terms of, you know, the longer term period, you know, as I mentioned we see the average rig count quarter on quarter going up 9% for the third quarter. You know, we won’t give you any projections past that today, but, you know, that’s based on, you know, the fact that we’re reactivating rigs and investing, you know, in the fleet the way we are, you know, you could make some assumptions there.

Fair enough. Okay. As it relates to – maybe this is sort of a side question, but coming back to the 7500 PSI pump, one way of maybe thinking of it, and maybe you want to try to refute that, is it’s easy for operators to want that today because of the availability of rigs. And yet if you were to try to get an incremental pricing for that capability, right, as you see this 250 rig count tightening, perhaps we reveal just how important it is to the operator I guess I’m just curious for some thoughts in response to that suggestion. In other words, how price-sensitive do you think operators are as it relates to having this full suite of capabilities of the highest capability rig today?

You know, we’re certainly, you know, we’re in a place in the market where we’re just starting, you know, to see the rig count increase, and, you know, we’re just starting to reactivate rigs. We’re having these types of discussions with customers and we’re working through rigs that have these upgrades already. You know, we – as I mentioned we have the potential to upgrade another 79 of our APEX rigs in various ways that are required by the market, so, you know, as we work through existing inventory, you know, as Patterson-UTI and as an industry, you know, once that inventory is, you know, finished, then, you know, the discussions will likely change for ourselves and other drilling contractors to be able to upgrade.

Right. So there’s more of a price – I guess your point is there’s more of a price discovery once you’ve exhausted the current inventory.

Exactly.

Sure. I guess that makes sense. If I may, one more, even if I’m going to switch gears and ask about pumping. I guess I was nicely surprised to hear but interested to see that 90% of your revenue generation on 24 hour work in the quarter – which I guess I have sensed that there was a less or maybe a lot less 24 hour work being done for various reasons in the industry. I guess I’m curious for how much you were able to control that and to pick work that had that. And I guess by extension, assuming that there is some recovery – I recognize you’re not calling for that in 3Q, but assuming there is, do you feel like you’ll be able to hold on to that? And is that an important driver in continuing to do 24-hour work specifically as you ramp back up?

So as I mentioned, and as you stated, 90% of our work was 24 hours but we still have open space in the calendar. So it’s 24 hours but not exactly 7 days a week every week. What we want to try to do is fill out the calendar. We’re very fortunate that the customers we work for have mostly transitioned over the last few works to where they can manage the 24-hour work on their end. And that’s an important part of the equation. But it is a very difficult market. You can’t really be selective right now. As I mentioned, we’re just fortunate that our customers have moved in that direction. We still need to try to fill out the calendar as activity continues to improve. And right now that’s where we think we have some upside. We’re certainly not going to reactivate any spreads on pressure pumping until we can get a significant price uplift to cover the cost. Because we have had the discussion on drilling this morning but the cost to reactivate a frac spread is much higher. And so we have to get a price uplift to be able to do that. But we’re certainly focused on trying to fill out the open space in the calendar wherever we can, you know, as activity increases.

Okay. I think that helps me put it into perspective. So thanks. I’ll turn it back.

Thanks.

Thank you. I’m going to go back to Mr. Marc Bianchi from Cowen and Company. Your line is open. Okay. Turning to the queue, our next question or comment comes from the line of Marshall Adkins from Raymond James. Your line is open.

Good morning, guys.

Hey, Marshall.

Now that all the softball questions have been asked, I want to go to the harder ones. You mentioned in the commentary, Mark, that your focus is now shifting to kind of scaling up the business. So I presume you’ve all thought through all the key issues and the bottlenecks and whatnot. Could you share with us what the challenges are going to be, going back up? And some specific questions, I mean, is it going to be more labor equipment? And differentiate between pressure pumping rigs. You know, how long would it take to double your rig count? Is there a lot of training involved? If you could hit on a lot of those issues, it would be helpful, I think, for all of us.

I’ll turn that to Andy. It seems like a hard question, Marshall.

Hey, Marshall. Yes, we are shifting gears to manage the reactivation of the drilling rigs. You know, we have had to kick back into recruiting process. We have had good success getting people back for this reactivation. But we, you know, we’ve certainly recognize that the labor market is going to tighten up. You know, the economy has been absorbing, you know, the people that the industry has had to unfortunately release over the last year and a half, and so, you know, as we extend this process, it gets more challenging and we’ll have to move back to our national recruiting campaign which we had back in, you know, 2013 and 2014. So that’s really the big challenge for us. In terms of equipment, you know, our equipment that’s stacked is in good condition and ready to reactivate. But then, you know, the overreaching challenge, I think, for the industry is really going to be the capital. You know, we have been able to work on our balance sheet and improve our situation, but it’s really going to be capital costs that the industry is going to need to reactivate this – the equipment and you know, we’re comfortable that we have the working capital in place. We’re comfortable that we have, you know, available capital to reactivate for growth scenario. And we think that puts us in a very good position relative to some of our peers.

So that’s on the rigs. How about pressure, you’ve got a lot of stack equivalent. Is that stuff in good shape, it’s going to cost money to bring back out? Help us with that.

It is going to cost money. You know, we’ve looked at this. It’s, you know, for the first few spreads that we reactivate, it’s in the range of about $2 million per spread. The majority to that is labor. So, you know, we’re going to have to crew up almost a month in advance, and you know as we’re doing mostly 24-hour work, that’s, you know, roughly 100 people. So we’ve got that labor cost for a month before we actually start the work. We’ve got materials expenses. We may have some capital expenses in there as well. But it’s about $2 million for the first few spreads that we have to reactivate. Because of that we need to get a pricing uplift before we reactivate. And we have the working capital to manage this.

It sounds like it’s not a huge number. Last one from me associated with this is the – I’ve talked to several land drillers that have mentioned, you know, to double the size of their fleet and get all the people trained, they thought it would probably take at least a year to double, once you press the go button. Is that a reasonable number from your perspective, or would you think it’s quicker or later than that?

It’s not an unreasonable number but I think we could also move quicker if we need to.

Okay. Thank you all.

Thanks a lot.

Thank you. Our next question or comment comes from the line of John Daniel from Simmons & Company. Your line is open.

Thank you. Hey, I think you guys mentioned that full year CapEx will total roughly $170 million.

Correct.

But you’ve only spent about $53 million so far this year. Can you tell us why there will be such a big step-up in the spending in the back half?

You know, we have continued to work through inventory that we have had on the shelf, in terms of capital, you know, fluid ins, parts for rigs. So, you know, we haven’t had to move the cash, you know, as you’ve seen. But expect that in the second half of the year there will be a catch-up on that as we, you know, start to restock shelves with some inventory, along with upgrades on rigs where we’ll add 7,500 PSI systems in just reactivation and capital projects around reactivation of rigs.

Okay. But do you guys expense fluid ins?

No, we capitalize the fluid ins and depreciate them over a very short time period.

And that $2 million number per spread that you referenced, that is a capital cost? Or that is your expense cost for reactivating it?

That’s a cash cost. So that’s labor plus maintenance, OpEx plus any maintenance CapEx.

Okay. And then I would presume there’s some – okay. I’ll leave it there. I’ll follow-up. So it sounds like several of your peers are reactivating frac fleets but it sounds like you guys, you know, being a little bit more disciplined on price, will defer reactivating until – in those higher. So therefore, on the surface this would imply, you know, near term market share losses. Does that concern you guys at all?

No, we don’t see that. We don’t see that we’re losing market share. And in fact, you know, we think we’re getting – we’re definitely getting our share of the cash-positive work out there. So we think we’re doing this right thing. We think we’re, you know, being prudent with the assets. And we’re not going to reactivate unless we can cover the cost together.

Okay. All right. Last one from me and I’ll turn it back over. Can you just speak to your frac activity levels as they evolved during Q2, and then how does July utilization compare to, say, the average in Q2?

We don’t necessarily break it down by month that way, but quarter-on-quarter, everything is relatively flat, Q2 and Q3.

Okay. So July is trending exactly as Q2? Because the rig count, as you guys know, is up but your frac activity is flat?

Correct. Yes, the right count’s up, but the frac activity is relatively flat. Revenue is projected to be relatively flat.

Got it. Okay, thanks guys.

Thank you. Our next question or comment comes from the line of Michael LaMotte from Guggenheim. Your line is open.

Thanks. Good morning, guys.

Good morning.

Andy, if I could maybe just start on the frac side. Most of your competitors so far this earnings season have talked about just pricing being way too low, and, you know, the need to get it up. I’m just wondering, with so many in the business on the contractor side feeling that way, what’s really, in your mind, preventing pricing from getting where it needs to be? Is it just the asset overhang? Is it resistance on the part of the customer? Or is it just, you know, bad competitive behavior?

I think right now you still have bad competitive behavior. I think – you know, you see companies that are activating frac spreads into a market where you can’t raise price and get an uplift for that increased level of activity. And, you know, we’re trying to be prudent about that. You know, yes, we see the rig count rising but activity in frac is, you know, not really moving up yet. It’s moved up some across the industry. But, you know, there is a delay in how you – there is the natural delay of hydraulic fracturing following drilling. And so activity will eventually move up to follow the rig count. But no, we still see that – we still see competitive bids that, you know, we think that people are still out there at, you know, cash-negative pricing, even for some of the spreads that gets reactivated. And we just want to be prudent with our own assets. We think that, you know, the active spread count, if it does increase this way, that, you know, as the utilization does come up, it will eventually give us that opportunity to get that price lift that we’re looking for in order to reactivate a spread in the future as well.

Do you get the sense that customers are aware of, you know, the damage that’s being done to the industry because of current pricing? Do you think there will be much resistance when it finally comes?

I think there will always be resistance. That’s just the way it is.

Right.

But I think, you know, EMPs are still trying to get the best deal that they can get. And as, you know, utilization and capacity starts to tighten up because, you know, we’ve talked about in the past, you know, we’ve lost a lot of horsepower from this market. And so I think utilization will tighten up over time to the point where we can start to get the pricing uplift to reactivate crews that we’re looking for. And then it will be a little bit longer before we can actually get a, you know, a lift across the whole sector to raise pricing.

All right. And then last one from me. If I think about the distribution of equipment, both rigs and horsepower, if 90% of the activity increase is in the Permian, would you consider moving equipment from the northeast to the Permian, and would you do that on your own dollar, or would you try, you know, is there any way to get paid for it?

Well, we have moved equipment in the past. But we still have idle equipment in Texas that we have the ability to reactivate. So, you know, we would certainly want to work through all the equipment in Texas before we move any from the Northeast.

Okay. So that question is just premature, then.

I would say.

Okay. Thanks, Andy.

Sure.

Thank you. Our next question or comment comes from the line of Robin Shoemaker from KeyBanc Capital Markets. Your line is open.

Thank you. So, Andy, some – I’ve noticed some of the EMP companies that are prominent in the Appalachian are giving some indication that they’re going to pick up activity in the second half of the year, take advantage of the low oil service costs, of course. But you didn’t seem to indicate that, that was an area you’re seeing acceleration on the rig side more in terms of the duct activity. Is that correct?

So, in the rig side we’ve called out a 9% increase on average quarter-on-quarter for, you know, for all the basins that we work in. And that would include the Northeast as well, you know, in its proportion. So I think with natural gas prices on the strip, you know, there is the potential to do that in the Northeast. But, you know, I was just trying to just put a little color on the activity that we are doing right now in the Northeast in terms of pressure pumping, just to let everybody know, you know, the rig count has dropped off there. And so, you know, the activity that we’re performing right now is really duct related primarily. And then we’ll see a shift once drilling increases.

Right. Okay. So overall, the, you know, U.S. land rig count’s up about 60 rigs or something like 16% from the very lowest level. And do you see any – as operators are out there looking to hire a new rig, do you perceive that they are kind of going back to their preferred contractors? Or are they looking at sort of taking the lowest bid? Anything that would change the market shares of the established company’s post in this upturn compared to where it was, you know, prior to downturn?

As you can imagine, I think we’re seeing a little of both. I think we’re seeing some operators that, you know, stick with contractors that they’ve used, like ourselves. I think we’re seeing some operators that want to look around and see what’s available. So it’s going to be a mix, as we come out of this.

Yes. Okay. All right. Thanks, Andy.

Thanks.

Thank you. Our next question or comment comes from the line of Jason Wangler from Wunderlich. Your line is open.

Good morning, gentlemen. I was just curious, as you talk about the potential to upgrade APEX rigs, and understanding they’re probably all a little bit different, do you have an idea of what that ballpark cost would be, or even a range of it as you start to look at that process?

Yes. So we have 161 APEX rigs, 128 of those are 1,500 horsepower, you know, we talked about the number we have that already have most of these upgrades. And then we have, you know, a number that we still have the option to upgrade, depending on what it might be. So, you know, if there’s an APEX rig that doesn’t have a walking system, that’s about a $2 million upgrade. If it’s an APEX rig that doesn’t have a 7,500 PSI circulating system, that’s about a $1 million upgrade.

Okay. That’s really helpful. And again maybe just on those two points, as far as the timing that would take for you guys, from, you know, them coming to you and saying, hey, I want that upgrade, to getting it in the field, assuming it wouldn’t be too long, just kind of curious on that timing.

You know, we keep some inventory in place, so depending on the upgrade, it could be anywhere from four to six weeks.

Okay. So very immediate. Okay, great. Thank you for that color. I’ll turn it back.

Thank you. Our next question or comment comes from the line of Judd Bailey from Wells Fargo. Your line is open.

Thanks. Good morning. A follow-up question. Just thinking about your incremental margins on pressure pumping, Andy, I think you said that you can accommodate about a 25% increase in activity with your current fleet, currently active fleet. And I assume on that first 25% increase, we should assume higher incremental margins. I don’t know if we can – if you would be comfortable giving us a range to think about. But then as you start to reactivate equipment eventually, do those incremental soften a bit as you have some friction cost in upgrading or reactivating? Or can those incremental remain high because you’re passing through higher pricing as well? I’m just trying to think about the lumpiness and think about your incremental margins as your revenues start to increase. So any color you can provide would be appreciated.

Well, I think you have helped describe the challenges well because there’s a few different moving parts in there that are going to move the margins up and down. So yes, as I mentioned, with the current equipment that we have active, we have room within the calendar to add 25% or more on activity. So, you know, that does have the ability to, you know, at the field level, you know, for the crew, the margin probably doesn’t change. But yet we’re covering costs within the business by doing that. And so, you know, we do get some uplift there. So, but then if – in the scenario of reactivation we would have to get a, you know, pricing uplift to help us cover the cost of that. So we would certainly look at that. And then, you know, there’s the whole timing process because if we were into a scenario of reactivating a spread, we would be incurring costs for a period where we’re not generating revenue. And so you have that moving piece in there as well.

Okay. And any sense of what the disparity in incremental margins could be as we think about, you know, increasing utilization on the active fleet versus when you start to reactivate it, you start reactivating equipment?

No, I think there’s just too many moving pieces there to try to, you know, put a number out.

Okay. And I guess, just to clarify, are you having discussions now with customers over reactivating equipment, pressure pumping equipment at your price point you need? Or is that not the case?

I would say pricing and pressure pumping is still unsustainably low and does not allow us to reactivate a spread.

Okay. That’s fair enough. And then just one last one. The pressure pumping guide for revenue, flat, I think you said, sequentially in the third quarter with the rig count starting to move up, any more color on kind of the moving parts there? Maybe certain contracts or anything on why revenue wouldn’t move up in the third quarter sequentially?

There’s just a natural delay from horizontal drilling to, you know, pressure pumping. And so even though the overall U.S. rig count has moved up, a lot of those early rigs that were activated were drilling, you know, smaller rigs drilling vertical wells. So you’re just starting to see more rigs moving into horizontal work. So you’ve got that natural delay, you’ve got increases oil. You’ve got a decrease in natural gas. So there’s a few moving things moving there as well.

Okay. Great. Thanks. I’ll turn it back.

Thank you. Our next question or comment comes from the line of Waqar Sayed from Goldman Sachs. Your line is open.

Thank you. Andy, as you’re signing these new six-month contracts for drilling rigs, is the early termination penalty clause still included, or the market is soft to add that clause?

No, it’s still included.

Okay. And secondly, on the pressure pumping side, one of your competitors mentioned that they’re seeing or hearing that some of the larger pressure pumping companies are actually increasing prices. But from your comments before, it doesn’t seem that you were noticing that. Is that correct?

We don’t see large pressure pumping companies increasing pricing.

Okay. And then just final questions. Could you talk about your fracs and logistics network. Where does that stand? You know, have you invested in trucking or railcars or anything? Could you describe that?

Sure. You know, to describe it best, I need to roll back the clock to when we were busy back in 2014 and we were operating almost 1 million horsepower back then. We were moving sand from multiple mines across the U.S. to the work that we were doing. We were moving typical white sands. We were moving regional brown sands. We were doing this with railcars that we have under long-term lease, which we still have available today. In 2014 we also increased the number of sand-hauling trucks that we own. We do own a number of our own sand-hauling trucks. And so we have infrastructure in place including rail spur leases, storage facilities. We have the capacity to manage the sand for 4 million horsepower. So no challenge there in terms of our logistics. I think, you know, there’s always opportunities to improve logistics and we’re certainly going to look at that as the market has increased the sand concentrations, you know, over the last year and a half. But we’re still confident that we can manage and move the amount of sand and materials that’s required. In 2014, we didn’t miss any work during that very busy period of Q3 for not having sand at the well site to pump the job. And so, you know, we’ll still use the same team that was managing it then will continue to manage it, and we’ve actually added to that team since then as well. So we think we’re in good position to do that. And we’ve already started discussions with some of the sand suppliers just to make sure that we have access to the sand that we need.

What proportion of your sand are you buying at the mine gate right now versus delivered at the well site? Or is it all 100% at the mine gate?

I don’t have that number for you. It’s a mix. If we buy some sand directly from the mines right there. And then some of it, we might work with a sand supplier for some of the logistics as well. So it really just depends on type of sand, where the sand is going, et cetera but we do both.

Okay. Great. Thank you very much.

Thanks.

Thank you. Our next question or comment comes from the line of Marshall Adkins from Raymond James. Your line is open.

I’m back. The ducts, you mentioned those a few times, Andy. And then obviously it’s a question we wrestle with a lot, and I don’t know if we have a lot of clarity on it. How many ducts are we working on now? And what is the potential size? Do you have a feel for that? You get to see the drilling side and the frac side. Does it seem to you like we’re starting to work off those ducts? I guess this is my question.

So specifically in the Northeast – I’ll start there. You know, we said back in the springtime, you know, one of the conferences that you might have been at, that, you know, we counted around 400 ducts up in the Northeast. And we have a good footprint and we certainly know every customer up there. And so we don’t think that number is too far off. Sometimes I think the definition of what makes up, you know, the duct within the stats might be different on how people count them. We’re looking specifically at the wells that were just parked on the side in inventory, and not between, you know, the drilling rigs and the frac groups. And so we see that we’re working off some of that inventory now. And that’s, you know, driving a good portion of our business right now in the Northeast. So, yes, I would say we are working off ducts in the Northeast. In Texas it’s harder for us to know and get a full view of it. And then of course we hear about ducts in other regions of the U.S. that we don’t participate in pressure pumping. But we think that, you know, the ducts are big part of our business right now in the Northeast. And that will shift to more of the work behind the drilling rigs as drilling activity improves in the Northeast.

That’s actually great insight. All right. So the follow-up there is a sense of how many of those – let’s say the number was 400, just to pick the number. Are we five into that or are we 25 into that, working at all?

I think it’s hard for us to say right now.

All right. It’s hard for any of us. I figured I would ask. Thank you all.

Thanks.

Bye.

Thank you. Our next question or comment comes from the line of John Daniel from Simmons & Company. Your line is open.

Hey, thanks for putting me back in as well. Hey, Andy, for next year, can you speak to a willingness to build new rigs anticipation of what might be even more robust activity beyond?

You know, that’s getting out there a little farther than we normally communicate, so, you know –

How about I – let me twist it this way, any of the capital spending in the second half of this year associated with the purchase of major component parts that will be used to support new build activity?

So in the $175 million on the drilling side, it’s maintenance and it’s equipment for upgrades. But that doesn’t include any inventory or any parts for building new rigs.

Okay. And then the last –

It’s just going to be demand-dependent. It depends on what WTI does, of course, and how fast the rig count moves up and how fast we work through this 250 rigs roughly that we count out there that have all these full specifications that customers are asking for now, and then the available upgrades.

All right. I mean, you guys have a good enough balance sheet where you can be opportunistic, I guess. That was the reason for my question. Take advantage of low prices.

And we like to think that we can be opportunistic if that opportunity comes up.

Fair enough. Can you tell us what your contract coverage is, on average in 2017?

No, I don’t have that number.

Okay. All right, thanks, guys.

Thank you.

Thank you. I’m showing no additional audio questions in the queue at this time. I would like to turn the conference back over to management for any closing remarks.

Thank you, Howard. We would just like to thank everybody for participating in our second quarter 2016 earnings conference call and look forward to speaking with you again when we report third quarter. Thanks, everybody.

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