Patterson-UTI Energy Inc (PTEN) 2020 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to Patterson-UTI Energy's Second Quarter 2020 Earnings Conference Call. (Operator Instructions) Please be advised that today's conference is being recorded. (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, Julianne. 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 3 and 6 months ended June 30, 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 in this conference call that state company's or management's plans, intentions, beliefs, expectations or predictions for the future, are forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995, the Securities Act of 1933 and the Securities Exchange Act of 1934. These forward-looking statements are subject to risks and uncertainties as disclosed in the company's annual 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 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 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 noncash 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 noncash 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 1/3 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 costs 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 the operator's analysis. Unfortunately, the Western Canadian market has not been able to financially justify that level of technology for the last couple of years, and we don't believe that activity levels are going to improve in the foreseeable future.

As of June 30, 2020, we had term contracts for drilling rigs providing for approximately $335 million of future dayrate drilling revenue. Based on contracts currently in place, we expect an average of 51 rigs operating under term contracts during the third quarter and an average of 38 rigs operating under term contracts during the 4 quarters ending June 30, 2021.

Turning to the third quarter. We expect that our rig count, including rigs on standby, will be approximately 59 rigs, in line with our current rig count. The proportion of rigs that are idle but generating revenue is expected to increase to approximately 30% of our expected rig count, which will be further dilutive to our average rig revenue and cost per day.

We do not expect any lump sum early termination revenue in the third quarter. Additionally, with our average rig count expected to be down more than 25% quarter-over-quarter, our costs will be negatively impacted by lower fixed cost absorption. Accordingly, margin per day is expected to be approximately $8,600 for the third quarter.

Turning now to pressure pumping. We averaged 4 active spreads during the second quarter, in line with our expectation. Pressure pumping revenue for the second quarter was $59.5 million, with a margin of $3.3 million, which was also in line with our expectation.

Given the magnitude of the downturn across the industry in the second quarter, we are very pleased with these results.

Pressure pumping restructuring costs during the second quarter was $31.3 million and included expenses for closing and consolidating facilities, severance, and for exiting contracts with vendors that we no longer intend to utilize. We believe these changes are structural to the business and will result in significant cost savings, making our pressure pumping segment much leaner and more competitive.

Excluding restructuring charges during the second quarter, as expected, we generated positive pressure pumping adjusted EBITDA. I believe that as a company, we continue to deliver Tier 1 operational performance in the field. One of our spreads recently set a customer record for pumping 23 stages in 24 hours and ultimately ended up completing 440 stages over 31 days. Our team at Universal Pressure Pumping likes to say that they are setting the pressure pumping standard, and I agree that they are doing just that.

Turning now to the third quarter. We expect a slight improvement in frac activity, with revenues increasing approximately 10% and we expect to be positive cash flow.

Turning now to directional drilling. Revenues were $11.7 million, and operating costs were $12.3 million. Activity during the second quarter was lower-than-expected, given the sharp drop in the horizontal rig count. Restructuring costs during the second quarter associated with directional drilling were $3.2 million, and we expect to reduce annual directional drilling operating expenses by approximately $10 million.

During the second quarter, our Superior QC business commercialized its latest well placement data analytics, HiFi Navigation. This new remote operations product provides wellbore position interpolation between survey stations based on well steering operations in order to improve the operator's well placement operations and improve overall drilling performance.

For the third quarter, we expect directional drilling revenues of approximately $10 million and gross margin of approximately breakeven.

Turning now to our other operations, which includes our rental, technology and E&P businesses. Revenues in the second quarter were $8 million, with direct operating costs of $9.1 million. Our E&P operations were negatively impacted during the second quarter as we chose to curtail oil production rather than sell into what was an extremely oversupplied market. We also took a $1.1 million charge related to a lease that we allowed to expire rather than drill in the current market.

For the third quarter, we expect revenues to be flat with the second quarter and for gross margin to be approximately breakeven.

Before we open the call for questions, I wanted to recognize the response of our team to this -- to the record decline in drilling and completion activity this quarter. Their efforts and execution quickly aligned our structure with the changing activity levels and helped to improve our margin results and maintain our strong liquidity position, while maintaining strong operational performance.

While we have taken dramatic steps to align our structure with current market conditions, we have not taken our eyes off the future of our company or the industry. We continue to invest in our technology initiatives around both automation and remote operations as we believe the leaders in these technology areas will be the winners coming out of this downturn.

A recent well drilled in Texas showcased our abilities in these areas. Our combined teams from Patterson-UTI with an APEX super-spec rig, MS Directional with the latest generation of Mpower MWD and MPact Motors and Superior QC's remotely operated HiFi Nav advanced wellbore placement algorithms, all work together with an operator to drill arguably one of the most complex directional wells in the U.S., where the horizontal section is in the shape of a U and more than 10,000 feet long for production from the 2 lateral sections. The well was jointly planned and executed with the operator, where the directional drilling operation had low enough tortuosity. It did not even require any high cost rotary steerable systems to complete the complex shape across such a long horizontal distance.

We are excited about this drilling success and look forward to the next complex well construction challenge that pushes the technical envelope.

We've seen over the history of our industry where major downturns have helped to drive technology adoption in the oilfield in order to improve performance, even when budgets are tight. In drilling, we saw the industry accelerate the move towards AC high-spec rigs following 2008.

Similarly, super-spec rigs were the rig of choice after 2016. We believe the next move will be towards more remote operations and automation technology, layered onto existing rig assets. We believe that we are well positioned with our various technologies at Patterson-UTI, including our Cortex operating system to facilitate the automation of discrete operations and our Cortex edge data servers for the next-generation of drilling data analytics.

Wrapping up. These have been difficult times with difficult decisions for our teams, and I would like to commend them again for their business and operational execution. With our strong operational performance, technology capabilities and our strong balance sheet, I am confident that we will emerge from this downturn even stronger.

With that, we would like to thank the hard-working men and women who make up this company. We appreciate your continuing efforts. Julianne, we would now like to open the call to questions.

(Operator Instructions)

Your first question comes from Sean Meakim from JPMorgan.

So Andy, to start off, I was hoping we could talk a little bit 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's been perhaps, more pressure among public E&P budgets relative to privates. Just curious, how you see that dynamic playing out? Or how that 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?

Yes. I think, Sean, there's multiple reasons that I can discuss for this. Our marketing teams have done a great job building great relationships 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 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.

Andy, I appreciate that. On the pumping fleet, you did about $60 million in revenue for 4 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 4 fleets? And then, what do you need to see besides in the improved pricing? And what else is needed to justify restaffing another fleet?

In the pressure pumping business, we've 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 on to 4 spreads on average, working through the quarter, which I think finished up better than probably some of our 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 on to 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 and revenue going into the third quarter. But that's about the most visibility we have at this point, I would say.

In terms of cost to reactivate, right now, they're minimal just because if -- 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.

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 2-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 or -- and then, related, maybe just getting to the punchline, 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. And 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 counts stabilizes at this point. It 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, 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 is 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 cost, the $14,000 to $14,500 per day of cost 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 can be some variability and some creep on those overall cost to operate the rig just because of the low rig count that we're at today. And so we still got some challenges that we have to work through, but the good news is that things are stabilizing at this point.

Okay. That's helpful. And then for a bigger picture question and sticking with contract drilling, there's been a lot of conversation in the marketplace about alternative contract structures. I wonder, if you might offer us the P10 house view on the potential adoption and your interest in potentially moving away from a dayrate model in this next cycle?

So we've been shifting some of our contracts, I would say, over the last 1.5 years to 2 years to various models that don't strictly include the dayrate. 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 dayrate. So you could -- about -- almost 1/3 of our contracts have some kind of performance combination to them or other element to them, that's more than just a traditional dayrate. So I think our teams have been doing a good job of 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 drilling completes. So 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 from Tudor, Pickering, Holt.

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, it 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 the 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. There may be some privates that want to pick up some rigs. The privates, I think, will react a little bit faster than some of the other operators out there. 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 at 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.

Okay. That's been super helpful. And then on the contract drilling side, I realize there's probably been almost 0 opportunities for price discovery. But if we look at your Q3 guidance, you're basically guiding to the 59 average rigs. If 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 6 months. But the majority of these are an evergreen type agreement, where we'll drill a number of wells and then the agreement gets re-signed, and it 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.

(technical difficulty)

or is somewhere in the low 60s and probably -- I think the guidance implies 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 as -- are people going to pick up rigs? Or are you going to -- do you expect some of those standby rigs to actually result in rigs rolling off as the standby period comes off?

Chris, I'm sorry. But for whatever reason, I think we missed about the first 3 or 4 seconds of your question. And so if you don't mind repeating, that would help us out?

Sure. Can you hear me okay, now?

Yes, we can hear you now.

Okay. Sorry about that. Yes. 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 it implies about 41 or so working in the third quarter. What do you expect through the trend for those actual working rigs rather than just a total rig count as reported including 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 is 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.

Okay. And then on the frac side, I mean, you called out one, I guess one particular pre pads on pretty outstanding performance. I don't know if that was throughout the quarter or just for a month or so? But is it at current pricing level? I mean in that kind of utilization that you had mentioned that was -- better on average than what you probably had in the second quarter. What kind of possibility for fleet do you think you can generate at these price levels?

Chris, I'm struggling to hear you a bit. 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 cost 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 some more inventory for 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.

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, you did 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.

Yes. 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.

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

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 as pretty minimal directional. It will be pretty minimal. The majority of what you'll see it'll 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 Marc Bianchi from Cowen.

Maybe following up to Chris' 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 in the 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'd also say, it's fair to say that we 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 this year, we don't see any issue.

Remember we started the year in 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.

Yes. Yes. Makes sense. Okay. Well, maybe switching over to the drilling side. The -- 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's 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.

Okay. Okay. Fair enough. And then as I sort of think about the role of your rigs, everything's on some type of contract that was written months there 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 at leading edge dayrates to the extent that there are, I mean, should you stabilize at this $8,600 level? Or would you think that 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 is 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'd 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 Crédit Suisse.

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 that changed 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 a 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, but -- 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.

Okay. 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 pretty small number. I think $10 million is probably overstating it. I don't have that at my fingertips right now there.

Your next question comes from Chase Mulvehill from Bank of America.

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 in automation operations. So maybe if you can speak to that about the capital costs 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 is going to be structurally the super-spec rig. It's 1,500 horsepower, but also has the draw works up at the same level as the drill floor, that gives the operators the most flexibility to walk around a pad and clear all the wellheads. And then on top of that, you -- 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 in 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 managed 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 -- is a 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 a $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?

Yes. 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 dayrate. And so we're already working under some performance contracts or various types of contracts that are out there that are just not straight dayrate. And working with our customers, the operators to find reasonable solutions to us and being able to improve their efficiency and us being able to monetize our investment and find a balance with the operator in that.

Great. That makes sense. 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 at 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 operations 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 nature, and again, we should expect to see those for the foreseeable future.

Your next question comes from Blake Gendron from Wolfe Research.

Yes. Just want 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 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 2/3 of the OpEx is labor. That hasn't changed. There's an element of OpEx as well that is in our our OpEx to operator rig that we 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 carrying an OpEx. They're not carrying the 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 kind of things are, what I would consider, something that we want to hold on to 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 -- we'll sit it in a 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 payrolls, separate benefits, separate structures that pose a separate cost challenge for us. And so we made a 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.

Got it. That makes sense. Appreciate the color. And then just a follow-up on your capital structure. You got plenty of runways to the 28s and 29s, to the degree that you generate cash over the next year or 2, 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 discussed 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 a kind of a meltdown across the industry. And we didn't feel it was right to do anything other than the sort of 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.

A 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 in 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 6 to 8 months, do you expect to see rig count pick up 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 our 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 at today's oil price come back. But I wouldn't say it would come back at 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.

And when you say further, is that in the $45 to $50 range? Or do you -- we need for $50 plus?

I don't think you need $50 plus. I think if WTI moves up into the upper 40s, that there are a 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 the 17, 18 rigs, how many would see contract expiration 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.

Okay. Fair enough. Now you mentioned that there was a crew that conducted 440 stages a month. Could you kindly comment on what -- where -- 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 with -- 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.

Fair enough. 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. It's -- this is a tough market. We're down to operating 4 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 4 crews active?

Yes. No change to that. We just -- we anticipate that we have increased level of activity. If something changes during the quarter, we'll let you know at the next call.

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

I just want to thank everybody for dialing in today. Again, I want to thank the hard-working 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.