Ladies and gentlemen, thank you for standing by, and welcome to Patterson-UTI Energy's Second Quarter 2020 Earnings Conference call. At this time, all participants are in a listen-only mode. After the speakers' presentations, there will be a question-and-answer session. [Operator Instructions] I would now like to hand the conference over to your first speaker today, Mike Drickamer, Vice President, Investor Relations. Please go ahead, sir.

Thank you, Julian. 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 six months ended June 30 of 2020. Participating in today’s call will be Andy Hendricks, Chief Executive Officer; and Andy Smith, Chief Financial Officer. A quick reminder that statements made on this conference call that state the Company’s or management’s plans, intentions, beliefs, expectations or predictions for the future are forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995, the Securities and Exchange Act of 1933 and the Securities and Exchange Act of 1934. These forward-looking statements are subject to risks and uncertainties as disclosed in the company's annual report on of Form 10-K and other filings with the SEC. These risks and uncertainties could cause the Company's actual results to differ materially from those suggested in such forward-looking statements or what the company expects. The company undertakes no obligation to publicly update or revise any forward-looking statements. The Company's SEC filings may be obtained by contacting the company or the SEC and are available through the Company’s website and through the SEC’s EDGAR system. Statements made 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’s my pleasure to turn the call over to Andy Hendricks for some opening remarks. Andy?

Thanks Mike. Good morning, and welcome to Patterson-UTI’s conference call for the second quarter of 2020. We are very pleased with our performance during the second quarter in both contract drilling and pressure pumping. With our largest business, contract drilling, we are especially pleased with our results, as we were able to act quickly to reduce costs and increase margins. We greatly appreciate our strong customer base for their support, and we believe we have seen improvements in market share in active contract drilling rigs and in pressure pumping spreads as a result of the strength of our commercial relationships. Our employees have done a great job, and we appreciate all of their efforts during these extraordinary times. We continue to prioritize the health and safety of our employees and their families and continue to take measures in the field and in our facilities to provide a safe and healthy working environment. I will now turn the call over to Andy Smith, who will review the financial results for the quarter ended June 30. I will then comment on our operational highlights, as well as our outlook before opening the call to Q&A. Andy?

Thanks Andy. As set forth in our earnings press release issued this morning, for the second quarter we reported a net loss of $150 million or $0.81 per share, which includes certain pretax charges totaling $55.8 million and a $4.2 million pretax gain related to an insurance settlement. Excluding these items, the net loss for the quarter would have been $105 million or $0.56 per share. The $55.8 million of pretax charges includes $38.3 million of restructuring costs and $17.5 million of non-cash impairment charges, of which $8.3 million is included in depreciation, depletion and amortization and is related to the closure of our Canadian drilling operations. And $9.2 million is included in other operating expense to reduce the carrying value on our balance sheet of a deposit placed in 2017 for future sand purchases. Of the $38.3 million of charges, only $7.5 million was a cash outlay during the second quarter. Excluding the restructuring charges and non-cash impairment charges, adjusted EBITDA would have been $61.6 million for the quarter. Turning now to the balance sheet. Our cash balance at June 30 was $247 million, an increase of $95 million from last quarter, largely due to a decrease in working capital excluding cash. Our liquidity improved to $847 million, including $600 million available under our undrawn revolver. Our balance sheet remains favorably positioned with a relatively low debt to cap and only limited near term maturities that can easily be handled by cash on the balance sheet. Our 2020 CapEx forecast remains unchanged at $140 million. Before I turn the call back to Andy for the third quarter, we expect SG&A of approximately $22 million, down approximately $2 million from the second quarter. We expect depreciation, depletion, amortization and impairment expense of approximately $157 million and an effective tax rate of approximately 14%. Lastly, we will be paying our quarterly cash dividend of $0.02 per share on September 17, 2020, to holders of record as of September 3, 2020. With that, I’ll now turn the call back over to Andy Hendricks.

Thanks Andy. In contract drilling, our average rig count for the second quarter was 82 rigs, down one-third and in line with our expectation. I am pleased that our rig count has outperformed that of the broader market during this tumultuous time. In addition to our contract coverage and our fleet of technically advanced super spec rigs, I believe our outperformance is also due to the diversification of our customer base, probably the broadest in the industry, and our geographic footprint. We operate in all of the major unconventional drilling plays in the U.S. and have strong commercial relationships with customers ranging from global IOCs to well-capitalized privates. During the second quarter, approximately 20% of our rigs that earned revenue were idle. These rigs typically generate revenue at a discounted rate but have minimal associated costs, which is therefore dilutive to our average rig revenues and cost per day but relatively neutral at the rig margin per day line. Considering this mix impact, average rig revenue and cost per day decreased sequentially during the second quarter, with average margin per day increasing by more than $2,000 per day and exceeding our expectation, due to both higher-than-expected revenue per day and lower-than-expected cost per day. The biggest driver for the better-than-expected margin per day was a significant effort by our team to reduce cost by aligning our structure with the changing activity levels. In the Western Canadian market, given our longer-term outlook, we closed our Canadian drilling operations during the second quarter, and we are currently marketing those assets for sale. We were very pleased with the drilling performance by our team and technology in Canada, where the APEX XK rig that we previously had in the market had the leading multi-well pad footage performance in the Montney basin according to…

[Operator Instructions] Your first question comes from Sean Meakim from JPMorgan. Your line is open.

So, Andy, to start, I was hoping we could talk a little about some of the dynamics that you’ve experienced that have led to that relative resilience in your rig count relative to the overall Lower 48. Exposure to the Northeast certainly has helped, but it sounds like aside from the majors, there has been perhaps more pressure among public E&P budgets relative to privates. Just curious how you see that dynamic playing out or how it has played out for your fleet? And then how does that inform your look forward in terms of activity for the balance of the year?

I think, Sean, there is multiple reasons that I can discuss for this. Our marketing teams have done a great job building great relationship with the customers. Our operations teams continue to execute in the field in top tier performance. And if you look at this broad base of customers that Patterson-UTI has traditionally always have. We work for some of the largest oil companies, and we will work for private companies that most people haven’t heard of, but they’re also well capitalized. And we’ve had these relationships in place for a long time. And our businesses have done a great job working with customers in this downturn and these relationships have had us – allowed us to have these kind of tough discussions in a very difficult environment and hang on to work at times when it might have been difficult otherwise. So I want to congratulate our teams for the great work that they’re doing in the field and once again I want to thank our customers because it’s been a lot of difficult discussions this quarter. But I think we’ve all worked together to find a good outcome in a very challenging environment.

Well, thanks Andy. I appreciate that. On the pumping fleet, you did about $60 million in revenue for four fleets. So that’s $60 million annual revenue per fleet. You’re expecting 10% improvement in 3Q. How much of a gap would you say there is between the volumes that you had in the second quarter, maybe on average for the quarter, and the capacity for those four fleets? And then what do you need to see besides any improved pricing? What else is needed to justify re-staffing another fleet?

You know the Pressure Pumping business, we have had some challenges in the past. We’d underperformed. We really needed to be able to show the market that we could run this business the way it needed to be run. The way we’ve run it historically. We’ve been in the business for a long time. And I think this quarter finally highlighted during very difficult challenges that we have a lot of experience running the Pressure Pumping business and we were able to hang onto four spreads on average, working through the quarter, which I think finished up better than probably some of our of competitors that are out there in the field. But it was a very difficult and challenging environment. I don’t want to understate what happened in the second quarter. And our teams did a great job hanging onto the work. Pricing is still a big challenge out there in the market. It was before we even got into this downturn after the decline in activity in 2019, and pricing remains a challenge in this environment. But we do see some opportunity to increase activity in the third quarter. We’re also cautious about how much activity we take on because we don’t want to spend any more money and accelerate any kind of OpEx or CapEx going into the third quarter just because we don’t have a lot of visibility into the fourth quarter and suspect that given where commodity prices trade, the fourth quarter could have its traditional strong seasonality in the second half and could see some slowdown at that point. So I think we’re a little bit cautious. We do think we can get a bump by about 10% in activity in revenue going into the third quarter, but that’s about the most visibility we have at this point, I would say. In terms of costs to reactivate, right now they’re minimal, just because if we needed to reactivate a spread, it wouldn’t take much since some of these spreads were working just not too long ago, just a few months ago. So any near-term reactivation would have very minimal cost to it. And we could bring people on fairly quickly to do that without a lot of overhang on compensation costs. So those general reactivation costs would be fairly low. We don’t have a lot of visibility that we need to do that, but we do see potential to increase the amount of activity in the third quarter by about 10%.

Your next question comes from Tommy Moll from Stephens. Your line is open.

So your daily margins on the contract drilling side were certainly above expectations in second quarter. And I’m trying to think through what the implication might be going forward. So I guess a two-part question here. Any idea how much longer you may have a big chunk of the fleet on standby, just asking that given that it kind of skews the daily P&L metrics that we look at. And then related, maybe just getting to the punch line, is 14,000 to 14,500 a day still a fair range to think about for “normalized daily cost”? Maybe that will help level set expectations?

So in terms of the number of rigs that are on standby, it’s really going to be market driven at this point. We just don’t have much more visibility than what we’ve given you in the third quarter. The good news is, we’re saying that our rig count stabilizes at this point and remains fairly steady. We don’t expect our rig count to go down. We still have some movement in the rig count, if you’re watching the maps, we may have a few rigs go down and a few rigs come up in combination. But, overall, we see that rig count stabilizing at this point, which is a positive after what we’ve been through in the second quarter. But it will be up to the customers to decide when they take rigs off standby and put them back to work. And certainly, given where WTI’s trading at this level, it doesn’t give us a lot of visibility that we’re going to see much of that right away. So we just don’t have any visibility on that. So it’s hard to answer how long some of these rigs are going to be on standby. In terms of the costs, the $14,000 to $14,500 per day of costs to operate a rig is a normalized cost, but we’re now at a level of rig count where it’s difficult to get the fixed cost absorption that we need to get as well. So there could be some variability and some creep on those overall costs to operate the rig, just because of the low rig count that we’re at today. And so we’ve still got some challenges that we have to work through, but the good news is that things are stabilizing at this point.

And then for a bigger picture question and sticking with contract drilling. There has been a lot of conversation in the marketplace about alternative contract structures. I wonder if you might offer us the PTEN house view on the potential adoption and your interest in potentially moving away from a day rate model in this next cycle?

So we’ve been shifting some of our contracts, I would say, over the last year and a half to two years to various models that don’t strictly include the day rate. Some include some performance. Some include some other elements in there. When we looked at the stack of contracts that we had in place in mid-July, about 30% of those contracts in place had other elements than just a day rate. So you could, about almost a third of our of contracts have some kind of performance combination to them or other element to them that’s more than just a traditional day rate. So I think our teams have been doing a good job working with the customers to find solutions to the challenge that we all know that’s out there where we continue to drill faster; we continue to improve efficiencies. And we need to try to monetize that as a drilling contract. I think our teams are doing a good job and they’re moving in that direction. And that number was around 30% in mid-July.

Your next question comes from Taylor Zurcher with Tudor Pickering Holt. Your line is open.

Andy, I wanted to ask on what the discussions are like with customers, both on the rig side and the frac side. I know on the frac side it sounds like you’re going to be cautious adding incremental spreads Q3 and beyond. But industry-wide it feels like frac activity kind of ticked up in June and probably more so in July. And just curious what your discussions are with customers about adding frac spreads and/or rigs in the back half of the year?

Let’s start with the frac. There are a number of customers that are out there talking to us, talking to other companies about increasing their activity. That may be adding spreads that may be just working current spreads at a higher number of stages per month or per quarter. So we’re certainly involved in those discussions. And I think the industry will see a higher level of frac activity in the third quarter. We’re going to be cautious about that as we approach those because we want to try to keep our costs in line. We’ve made structural changes to the organization that we think can hold up for the long term. We think we can, over time as activity improves in general, grow the business without growing these structural costs that we’ve taken out. So we want to be careful about that. I also would like to see pricing move up in frac. And we need activity to grow to push the pricing. And I think there’s room for pricing to come up in frac. It’s been at a level that’s been a real challenge, but the improved activity could help that a little bit as well. Now there’s still a lot of spreads that are on the sideline and a lot of companies that want to get spreads to work at just about any rate. But over time, if we can get the activity up, that’s going to help pricing over time. In terms of drilling, our current visibility is that things are stabilizing. But in general, I’d say the rig count is stabilizing. To really drive the frac business, we do need the rig count to move up and some point to increase the number of wells in inventory because what you’re seeing on the frac is response to going back and fracking wells on pads that were halted during the second quarter as activity came down really quick. So we do need those inventories of wells to increase, so we do need the rig count to move up to really help the frac business. Right now, we don’t have that visibility. And I think a lot of that’s just going to depend on how commodity prices trade throughout the rest of the year.

And then on the contract drilling side, I realize there’s probably been almost zero opportunities for price discovery. But if we look at your Q3 guidance, you’re basically guiding to 59 average rigs. You’ve got 51 term contracts, so that would imply at least a little bit of spot activity in there. And so at a high level, is there any way you could help us think about where pricing is on a leading-edge basis on the drilling side moving forward, or at least in Q3?

So I wouldn’t say we have a lot working at the spot level. We have a number of rigs, a small number that are working on agreements that are less than what we would consider term contracts because they’re less than six months. But the majority of these are an evergreen-type agreement where we’ll drill a number of wells and then the agreement gets resigned and continues on and drills a number of wells. So there’s really not a trade out there or a discussion with customers for us to really understand where we think leading edge or spot market sits in the drilling contract business. We’ve just come off of the fastest decline in the rig count in the history of the industry. And the customers just haven’t switched gears yet to have those discussions to say okay, what’s it going to take to put rigs back to work? So I just don’t think as an industry we know yet what leading edge really looks like.

Your next question comes from Chris Voie from Wells Fargo. Your line is open.

[Technical difficulty] is somewhere in the low 60s, and probably I think they got in supplies about 41 or so in the third quarter. I think you mentioned you expect the rig count to be flat going forward. What about the working rigs? Is that going to trend higher? Are people going to pick up rigs? Or do you expect some of those standby rigs to result in rigs rolling off as the standby period comes off?

Chris. I’m sorry, for whatever reason I think we missed about the first three or four seconds of your question, so if you don’t mind repeating that would help us out.

Sure. Can you hear me okay now?

Yes, we hear you now.

Sorry about that. So I just wanted to kind of look at the standby versus working rigs guidance. So I think on my math, you have about low 60s actually working rigs in the second quarter, and that implies about 41 or so working in the third quarter. What do you expect the time for the actual working rigs rather than just the total rig count is reported for standby going forward?

Yes, I think it’s really just dependent on what customers decide to do in terms of activating rigs and moving them from standby back to actually working. And as they do that, that creates a lot of movement in our numbers in terms of cost, revenue and margin per day. Right now we just don’t have more visibility than we’ve been able to give you. As I've said before, the good news is the rig count’s stabilizing. Operators have gone through a huge effort to reduce their activities in the second quarter and we’re not in a lot of conversations yet about what that looks like to take rigs from standby back to actually working.

And then on the frac side, you called out I guess one particular fleet [indiscernible] performance. I don’t know if that was throughout the quarter or just for a month or so. But if you took current pricing levels and given that kind of utilization s you had mentioned [indiscernible] better on average than what you had in the second quarter? What kind of profitability per fleet do you think you could get at these price levels?

Chris, I’m struggling to hear you but I’m going to answer the question. It sounds like you’re asking about frac pricing and then you can circle back on this if you want. Frac pricing was coming down last year when the industry slowed down about 30% in 2019. And so pre-COVID frac pricing wasn’t in a great position and with this recent downturn in the second quarter, I would say it’s caused a lot of equipment to be on the sidelines where you have a lot of frac companies that just want to get equipment back to work at whatever stage price they can get it back to work. And then figure out the math after that. So pricing is not in a good place in Pressure Pumping. We’re still intending to be positive cash flow. We’re doing I think our team is doing a fantastic job managing the costs in that business right now. I do believe that if there is an increase in activity in the third quarter and if you see a bump in the rig count after that, that creates more inventory per frac, I think there’s opportunity for companies to move the frac pricing up off this floor where it’s at because it’s certainly not sustainable where it’s at. And I think an activity increase would allow companies to bring that pricing up.

Your next question comes from Kurt Hallead from RBC. Your line is open.

Thanks for all the color so far. I think the follow up on my end was you gave us the kind of revenue impression on frac and you gave us the indication that frac was going to be cash flow positive in the quarter. So I guess the way I look at it is that you’d need at least, what, $4 million in gross profit in frac to be cash flow positive. Is that a fair way to think about it?

Yes, I would say it’s a little less than that. I mean, our CapEx for the remainder of the year in all of our businesses is pretty modest. But again, you’re not way off.

Our CapEx especially in frac was very front-end loaded. We don’t anticipate much CapEx spend for the rest of the year in any of the businesses but I’d say especially frac and directional drilling, very minimal CapEx.

Yes.

My follow up was going to be on the CapEx. So I think your guidance implies maybe about $20 million total CapEx in the back half of the year. So if you were going to split that among your segments, what would that mix look like?

It probably continues to be split about in the same percentage as what we did earlier. I mean, obviously, drilling will come down with fewer actually working rigs, Pressure Pumping, again, we just talked about is pretty minimal directional, would be pretty minimal. The majority of what you’ll see will be in drilling, but you’ll see a little bit more. You’ll see some more obviously in Pressure Pumping in the back half. Directional, I would say, is very, very modest.

Your next question comes from Mark Bianchi from Cowen. Your line is open.

Thank you. Maybe following up to Kurt’s question on CapEx. If we’re going to do $20 million in the back half of the year here, I mean, I know that that’s a very, very low level where you’ve been historically. But just thinking about the sustainability of that level if activity stays at these depressed levels, is that something you think you can continue to do?

I would go back to just saying that our CapEx was very front-end loaded. So the run rate on CapEx is not necessarily what you project into 2021, because we had some front end spend. So we can, what it costs to run a Pressure Pumping spread, what it costs to run a drilling rig in terms of capital cost, hasn’t really changed. It’s just that we were front-end loaded on a lot of these expenditures.

Yes, I’ll say it’s fair to say we have been using some parts that were on the shelf and some spares. And look, I don’t think it’s sustainable to run at these levels for a long period of time. But, certainly, for the remainder of this year, we don’t see any issue.

Remember, we started the year the first week of January with WTI trading around 62, and it was a different world and we were spending money getting ready for what was going to look like a fairly busy year. We just don’t need to buy a lot of parts right now.

Well, maybe switching over to the drilling side. You’ve got a large proportion of rigs on standby in third quarter. And I know from your largest peer that they’ve got a pretty big difference in the margin for standby rigs versus working rigs, which is something that seems different versus prior cycles. I’m just curious if that’s the case for you guys and if you could quantify that difference.

I think our case is a little bit different. And I think our margin for the standby rigs is not that much different than when they’re working for us. I mean, there is some differences and there’s going to be some variances by base and by customer. But I think that the way we approach that is a little bit different.

And then as I sort of think about the role of your rigs, everything’s on some type of contract that was written months or maybe quarters ago. What should we see? I mean, is this, if things don’t get worse from here in terms of the rig count and leading edge day rates to the extent that there are, should you stabilize at this $8,600 level? Or would you think there’s a lot more downside to that? Maybe just help us think about the range of outcomes.

It’s hard to know exactly what the continued outlook’s going to be past the third quarter in terms of everything that’s going on in global economics. But if you assume WTI stays where it is, rig count stays roughly where it is, we could see some change in the margin per day where it could come down based on contracts coming off. But that would be over a long period of time. We would be well into 2021 before we would see some changes because of the contract backlog that we have.

Your next question comes from Jacob Lundberg from Credit Suisse. Your line is open.

I guess I just wanted to ask in light of what looks like perhaps a structurally lower medium-term outlook for the U.S. markets, does that change at all how you guys are thinking about potentially shifting any assets to international markets?

For us, we’ve been very focused on U.S. Unfortunately, we made the decision to shut down Canada, which makes us now primarily a U.S.-based company with operations. So in terms of anything happening out of the U.S., I would say that’s just not in our area of what we’re looking at today. We do follow the markets in different places, and we’ve seen slowdowns everywhere. So it would be very tough for us, I would think, or any company, to move assets from the U.S. into international markets with some of the slowdowns that are happening in the international markets.

And then as a follow up, is there any cash outlay that you could quantify that you’re expecting in 3Q or 4Q related to the charges that you guys took in Q2?

Yes, I would say it’s probably in the neighborhood of $10 million or less. I don’t have that figure right in front of me in the third quarter. It was pretty minimal in 2Q, only $7.5 million. And that included most of what we paid in severance, and a lot of the cost savings are coming from severance, to be honest. And so I would say going forward it’s a pretty small number. I think $10 million’ probably overstating it. I don’t have that at my fingertips right now, though.

Your next question comes from Chase Mulvehill from Bank of America. Your line is open.

I guess, real quick, I wanted to talk about rig evolution and kind of how we think about the next stage of rig evolution across the U.S. sector. Basically, rigs are going to have to be upgraded to digital platforms that will actually enable remote and automation operations. So maybe if you can speak to that about the capital cost required to do that, how many rigs you think you have capable to do that, what it means for margin and then how you think peers will be able to respond and will they be able to kind of upgrade their rig fleet comparable to what you can do.

So I think that the good news in this story is that the rig structures that we have in our fleet are very competitive. I think the rig that’s going to be the most popular coming out of this downturn as we get into more of a recovery mode, the operator’s the most flexibility to walk around a pad and clear all the well heads. And then on top of that, with a super-spec rig, you’re going to want an AC control system, and we’re very well positioned in that space right now. The APEX rig fleet that we have is, can be easily transformed with our Cortex operating system at what I would consider even a minimal cost. It takes a little bit of time. It takes a little bit of OpEx, not much on the CapEx side, to do that. And that’s the good news in what we’ve done. Hats off to our team and the engineering groups at Patterson-UTI Energy for what they’ve come up with. But to layer on the CORTEX operating system, to layer on the Cortex Edge device for data analytics and data transfer is not a high cost, high capital item for us. And we’re really excited about the apps that we’re putting in place and things that we’ve done to integrate and automate certain functions, whether it’s controlling the directional capabilities on the rig or manage pressure drilling integration into the rig operating system. These are all very exciting places for us to be. We’re very well positioned. And, yes, there is some cost, but it’s not a huge CapEx needle mover in the overall budget.

Yes, I mean, just to follow up on that. I mean, if we were to think about the total value proposition to your customer with this kind of new rig offering, this digital offering, like how much ultimately incremental margin do you think you can capture? Is this like $100 a day? Is this $500 a day? Is it $1,000 a day? Like what’s the magnitude of margin accretion you think over time that you can get from this?

There is certainly extra margin in there for us. I think the market will determine exactly how much that is, and it’s kind of hard to have a lot of visibility on what that’s going to look like after the decline in activity we’ve just been through in the second quarter. But we’re very excited about our position in this space and feel very competitive in this area with what we can offer. As I mentioned earlier, about 30% of our rig contracts as of mid-July had terms in them that were different from just a plain day rate, and so we’re already working under some performance contracts or various types of contracts that are out there that are just not straight day rate. And working with our customers, the operators, to find reasonable solutions to us being able to improve their efficiency and us being able to monetize our investment and find a balance with the operator in that.

One real quick follow up on pumping. I think last quarter you said 65% of your $100 million cost savings initiatives were targeted towards pumping. Sorry if I missed it this call but is that correct? And if so, which pieces - which part of the cost structure are you attacking the hardest in Pressure Pumping?

Yes, so it’s a little lighter than that. Again, when we were last quarter we were estimating based on kind of what we were thinking we would see. We came in a little bit less than that, probably around 55% of the overall cost savings were in pumping. Most of that is basically layers of management and operation support and then there’s a sizable chunk of SG&A also that’s coming out. Some facilities shutdowns, things like that is really where we’re seeing it. So I would say most of them are structural in mature and, again, we should expect to see those for the foreseeable future.

Your next question comes from Blake Gendron from Wolfe Research. Your line is open.

Thanks for getting me on here. Just wanted to focus in on your comments about fixed costs on the drilling side, specifically within OpEx, can you just break out the various buckets and remind us what portion of that is fixed as it relates to some of your cost absorption comments? And then just looking at the rig count in the various basins it would make sense that perhaps a lot of the subscale providers move out of certain basins. What would you consider optimal scale at the basin level? And then if it makes sense for players to be exiting basins, are you seeing rigs moving into the Permian fairly substantially at this point with the rig count kind of depressed elsewhere?

So let me try to tackle those somewhat in order. So when you look at the cost to operate a rig, we’ve always said that about two-thirds of the OpEx is labor that hasn’t changed. There’s an element of OpEx as well that is in our OpEx to operate a rig that we call out within the drilling company. We don’t carry this in SG&A, but it’s engineering. So when we’re looking at engineering control systems, engineering data analytics systems, those are carried in OpEx, they’re not carried in SG&A. So they’re part of that cost and we’re still investing in technology. We think it’s the right thing to do for the future of the company. And so that also adds up into that OpEx on a per rig basis. So those are the kind of things that are there. So you’ve got compensation at the field level. You’ve got our engineering spend that’s in there, too. And so those kinds of things are what I would consider something that we want to hold onto right now. When you look at the various basins that are out there and what we consider to get critical, in the contract drilling business. We can work a single rig in a basin without a problem. We can scale the structure of that basin around that. We can provide support from a separate basin if we need to. The rig will sit as an island in a basin even if it’s a single rig and we can manage that cost. Where our challenge was in Canada, we had a number of rigs that we had up there. We hadn’t worked any recently and we just don’t have an outlook on the Western Canadian basin that we think supports the level of technology that we want to be able to operate and which is really our specialty in the super spec rigs, layered on with data analytics and other elements that bring technology to the table for the operators. And so with Canada being a separate country, requiring legal entities, separate payroll, separate benefits, separate structures that posed a separate cost challenge for us. And so, we made the decision to shut that down in the second quarter. We just don’t think that long-term the Western Canadian basin is going to support the level of technology that we work in the lower 48. And therefore, the rigs that we had up there, while they’re very good rigs, we just feel like it’s better just to shut that down and put those assets up for sale.

And then just a follow-up on your capital structure, you got plenty of run way to the 28 and 29s. To the degree that you generate cash over the next year or two, padding the balance sheet seems to be prudent. But the debt kind of traded down in the second quarter. I’m just wondering how you’re maybe viewing opportunistic buybacks of that debt at this point?

Yes, we discuss it with the Board periodically. And I think given – I mean I think it’s an understatement to call sort of the activity in this quarter dynamic. It was certainly kind of a meltdown across the industry. And we didn’t feel it was right to do anything other than to preserve liquidity. But as we go forward, we’ll obviously, look at those opportunities and discuss them with our Board and decide the best course of action.

[Operator Instructions] Your next question comes from Waqar Syed from ATB Capital Markets. Your line is open.

Thanks for taking my question, couple of questions here. Number one, just for maintenance type question, what was the cash flow from working capital in the second quarter?

It was about $100 million.

Okay. And how do you see that in the third quarter?

I don’t expect any significant changes. I don’t expect any significant increases or decreases to the cash flow. I think it’s going to be pretty neutral going forward from working capital.

Okay, great. And then, Andy, if oil prices should stay in this range of like $40 to $45 over the next six to eight months, do you expect to see rig count pick up in any magnitude from current levels?

I wouldn’t say rig count would increase in any magnitude. You might see some privates pick up some rigs. There are some plays and E&P actually drills in some plays where you can make money at $36, $38 a barrel. So there are some plays still out there. So it’s – we could have a few rigs here and there today’s oil price come back, but I wouldn’t say it would come back in any magnitude. I think we would need WTI to move up a little bit further to really drive rig count increases. And I believe that the early rig count increases would likely be in West Texas if WTI starts to move up further.

When you say further, is that in the $45 to $50 range or – we need $50 plus?

I don’t think you need $50 plus. I think if WTI moves up into the upper 40s that there are number of operators that economically could put rigs back to work and be profitable drilling wells at those levels. So I don’t think you have to get to $50 a barrel. I think that there’s certainly areas of West Texas, New Mexico, with operators that have held their land positions for a long time that could be economical if we get north of $45.

Okay. And of the rigs that you have on standby in the third quarter, let’s say 17, 18 rigs, how many would see contract exploration [ph] in the fourth quarter?

Yes, I don’t have that number in front of me, but I don’t think it’s a big risk for us either.

Now, you mentioned that there was a crew that conducted 440 stages a month. Could you kindly comment on which basin was that crew in and what were some of the characteristics of the job was it smaller stages or any other technology that was being implemented? It’s a pretty big number, for stages per month?

It was a large number. I’ll credit the team. I’d rather not call out the basin. It’s not necessarily public from an operator standpoint. I will tell you it wasn’t a particular piece of technology, but it was a lot of preplanning effort and a lot of credit to the operations team out in the field working with the operator to plan how they were going to do this. And being able to preplan the job and take some of the – what would be considered non-pumping time. And then push that into other areas so that you had some concurrent activities happening while they were doing it. So this is an area where it wasn’t necessarily technology, but it does illustrate that we have very good teams focused on being able to perform at the Tier 1 level, and that our equipment can do a great job in the field because that’s a lot of stages to be pumped.

Is that repeatable and do you think that industry would over time move towards that kind of figure?

I think it’s repeatable with this particular operator in their field, depending on how they have their pads set up and the number of wells that are ready to go. I don’t know if you get broad numbers like that across the U.S. just because this may have been somewhat basin specific. So it may not be repeatable from basin-to-basin, but it does show that in the industry we continue to improve the economics for the operator.

Now, Andy, you mentioned that in the pumping business you expect to be cash flow positive. What does that mean? Could you kindly elaborate on that?

I think in the second half of this year, we don’t anticipate having to spend much at all in terms of CapEx in pressure pumping. We expect to be positive EBITDA and positive cash flow in the business. This is a tough market. We’re down to operating four spreads. We do see some increase in activity in the third quarter. We’re going to call out 10%, but I think that we’ll just have to wait and see how that quarter shapes up. But I give a lot of credit again to our teams for getting costs out of the system and making us much leaner and more competitive.

And so, I assume that in the third quarter as well you’ll have four crews active?

Yes, no change to that. We anticipate that we have increased level of activity. If something changes during the quarter, we’ll let you know in the next call.

We have no further questions. I’d like to turn the call over to Andrew Hendricks for closing remarks.

I just want to thank everybody for dialing in today. Again, I want to thank the hardworking employees of Patterson-UTI. This was a really tough quarter. A lot of things they had to deal with, and everybody did a great job. And thanks, everybody, for calling today.

This concludes today’s conference call. You may now disconnect.