Q2 2020 Patterson-UTI Energy Inc Earnings Call
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Like to hit the conference over to your first speaker today, Mike Drickamer, Vice President Investor Relations. Please go ahead Sir.
Thank you Julien.
Good morning I.
I have Patterson UTI energy I'd like to welcome you today's conference call to discuss the results. The Threed six months ending June 30, 2020 <unk>.
During today's call will be Andy Hendrix, Chief Executive Officer, and Andy Smith, Chief Financial Officer.
A quick reminder, that statements made this comps called to speak to companies are mantras plans intentions beliefs expectations or predictions for the future or forward looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995, The Securities Act 1933, and the Securities Exchange Act of 1934. These forward looking statements are subject to risks.
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Statements made in this conference call include non-GAAP financial measures the required reconciliations to GAAP financial measures are included on our website Www Dot P 80 energy Dot com.
And in the company's press release issued prior to this conference call.
And now it's my pleasure turn the call over to Andy Hendrix for some opening remarks Andy.
Thanks, Mike Good morning, you're welcome to Patterson UTI Eyes conference call for the second quarter of 2020.
We're very pleased with our performance during the second quarters in both contract drilling and pressure pumping.
With our largest business contract drilling, we're especially pleased with our results as we were able to act quickly to reduce costs and increased 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 who've 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'll now turn the call over to Andy Smith, who will review the financial results for the quarter ended June Thirtyth.
Oh, then comment on our operational highlights as well as our outlook before opening the call to queuing <unk> Andy.
<unk>.
Supports our earnings press release issued this morning for the second quarter, we reported a net loss of $150 million were 81 cents per share, which includes certain pre tax charges totaling $55.8 million and a 4.2 million dollar pre tax gain related to an insurance settlement.
Excluding these items the net loss for the quarter would have been $105 million or 56 cents per share.
The $55.8 million pre tax charges includes 338.3 million.
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 <unk> and other operating expense to reduce the carrying value on our balance sheet of it.
Posit placed in 2017 for future stand purchases.
Well the $38.3 million charges, only seven and a half million dollars was a cash outlay during the second [noise].
Excluding the restructuring charges alone and kept 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 Thirtyth was $247 million, an increase of $95 million from last quarter, largely due to a decrease in working capital excluding cash.
Liquidity improved $847 million, including $600 million available under our Undrawn revolver.
Our balance sheet remains favorably position 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 SGN area of approximately $22 million down approximately $2 million from the second quarter.
We expect depreciation depletion and amortization impairment expense of approximately $157 million and an effective tax rate of approximately 14%.
Lastly, we will be paying our quarterly cash dividend of two cents per share on September 17, 2020 to holders of record as of September 3rd 20 Twond.
With that I'll now turn call back over to any hinders.
Thanks, Andy.
Contract drilling our average rig count for the second quarter was 82 rigs down one third and in line with our expectation.
I'm pleased that our rig count has outperformed 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 abroad us in the industry and our geographic footprint.
We operate in all the major unconventional drilling plays in the U.S. and have strong commercial relationships with customers ranging from global Io seized 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 lawn.
Considering this mix impact average rig revenue and cost per day decrease sequentially. During the second quarter with average margin per day, increasing by more than $2000 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're 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 operators 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 Thirtyth 2020, we had turned contracts for drilling rigs, providing for approximately $335 million of future day rate drilling revenue.
Based on contracts currently in place, we expect an average of 51 rigs operating under term contracts during the third.
And an average of 38 rigs operating under term contracts during the four quarters ending June Thirtyth 2021.
Turning to the third quarter, we expected or rig count, including rigs on standby will be approximately 59 rigs in line with their current rig count.
The proportion of rigs are idled the 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 lumpsum 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 $8600 for the third quarter.
Turning now to pressure pumping we averaged four active spreads during the second quarter inline with our expectation.
Pressure pumping revenue for the second quarter was 59, and a half million dollars, where the 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're very pleased with these results.
[noise] pressure pumping restructuring costs during the second quarter $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 one operational performance in the field.
One of our spreads recently set of 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.
[noise], 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 are superior to you see business commercialized its latest well placement data analytics, Hi Fi navigation.
This new remote operations product provides wellbore position interpolation between service stations based on well steering operations in order to improve the operators well placement operations and improve overall drilling performance.
For the third quarter, we expect directional drilling revenues are approximately $10 million and gross margin or approximately breakeven.
Turning now to our other operations, which includes our rental technology any MP businesses.
Revenues in the second quarter were $8 million with direct operating costs of $9.1 billion.
Our MP 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 help 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 drilling within apex Super spec rig.
Mr directional with the latest generation of empower MWD, an impact motors and superior Gecs remotely operated at high flying to have advanced Wellbore placement algorithms all work together with an operator to drill was arguably one of the most complex directional wells in the us where the horizontal section is in the shape.
For the you and more than 10000 feet long for production from the two lateral sections.
Well was jointly plan and executed with the operator, where the directional drilling operation had low enough tortue austerity did 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 were 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 falling 2008.
Similarly, we super spec rigs were the rig of choice after 2016.
We believe the next move will be towards more remote operations and automotive automation technology layered onto existing rig assets.
We believe that we're well positioned with our various technologies at Patterson UTI, including our cortex operating system to facilitate the automation of discrete operations and our Cortez 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 in our strong balance sheet I'm confident we will emerge from this downturn even stronger.
That we would like to thank the hardworking men and women who make up this company. We appreciate your continuing efforts.
Julien we would now like to open the call to questions.
Thank you as a reminder to ask a question. Please press star followed by the number one on your telephone keypad to withdraw your question. Please press the pankey.
Our first question comes from Sean Meakim from Jpmorgan. Your line is open.
Thank you Hey, good morning.
Good morning, Sean.
So Andy to start I was hoping we could talk little about some of the dynamics that you've experienced that have led to that relative.
Resilient and your rig count relative to the overall lower 48.
Exposure to the northeast certainly is helps but.
It sounds like a size and the majors theres been perhaps more pressure among.
But BMP budgets relative to privates I'm, 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 for in terms of activity for the balance of the year.
Yeah, I think Sean there's 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 exit would execute in the field.
In top tier performance and if you look at this broad base of customers at Patterson UTI has has traditionally always have we work for some of the largest oil companies and we will work for private companies that most people havent heard of but they're also well capitalize and we've had these relationships and play.
As for a long time, and our businesses have done a great job working with customers in this downturn and these relationships have had us.
Let us to have these kind of tough discussions in a very difficult environment.
And and hang on to work at times when it might have been difficult otherwise so yes, I want to congratulate our teams for the great work that they are 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 work together to to find a good outcome in a very challenging environment.
Thanks, Andy I appreciate that.
On the pumping fleet you did about 60 million in revenue for for fleet to that's 60 million annual revenue per fleet, you're expecting 10% improvement in Threeq you.
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 us for fleets.
And then what do you need to see.
Besides any improved pricing and what else is needed to justify restaffing another fleet.
Right.
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 run it historically, we've been in the business for a long time.
And I think this quarter finally highlighted during very difficult challenges.
We have a lot of experience running the pressure pumping business and we were able to hang on to four 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 understand.
State 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 was before we even got into this downturn after the decline in activity in 2019.
And in pricing remains a challenge and is 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 anymore money and accelerate any kind of opex or capex going ended 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 above the by about 10% in activity in revenue going into the third quarter.
But thats about the most visibility we have at this point I would say.
In terms of costs to reactivate right now they are minimal just because.
If.
If we needed to reactivate a spread.
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 a 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 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 amount of activity in the third quarter by about 10%.
Fair enough. Thanks, Sandy I appreciate that.
Thanks.
Your next question comes from Tommy Mall from Stephens. Your line is open.
Good morning, and thanks for taking my question.
Morning, Tommy.
So your your daily margins on the contract drilling side, we're certainly above.
Speculations and second quarter, and I'm trying to think through.
What the implications might be going forward.
So I guess 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 BNL metrics that we look at and then related maybe just getting to the punch line.
Is 14000 to 14 500, a day still a fair arrange to think about for quote unquote normalized.
Daily cost.
Maybe that'll 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 count stabilizes at this point and remains fairly steady.
We don't expect our rig count to go down we still have some moving in the rig count if you're watching the maps. We may have a few rigs go down in 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 on standby and put them back to work and certainly given where WPS 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 we're going to be on staff.
Okay.
In terms of the costs.
The 14014 500 per day of cost to operated rig.
He is a normalized costs, 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. Thank you.
And then for 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 if you might offer us the.
The 10 house view on.
The potential adoption and your interest and.
Potentially moving away from a day rate model and 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 in just a day rate. So you could about almost a third of our 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. 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.
That's helpful. Thanks, Andy and I'll turn it back.
Your next question comes from pillars, Dr. from Tudor Pickering Holt Your line is open.
Hi, Thank you and good morning.
Andy I wanted to ask on on what the discussions are like with customers. Both on the rig side in 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.
Industrywide of 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 a 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 maybe adding spreads that may be just working current spreads at a higher number stages per month or per quarter. So we're certainly involved in those discussions.
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 Weve you made structural changes to the organization that we think can hold up for the long term we.
We think we can overtime 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 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 theres still lot of spreads that are on the sidelines and lot of companies want to get spreads to work at just about any rate, but overtime. If we can get the activity up that's going to help pricing overtime.
In terms of drilling.
Current visibility 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 a 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 has response to going back in 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 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.
I think a lot of that's just going to depend on how commodity trite commodity prices trade throughout the rest of year.
Okay. That's super helpful and then on the on the contract drilling side.
I realize it's probably than almost zero opportunities for price discovery, but if we look at your Q3 guidance, you're basically guiding to 59 average rig as you've got 51 term contracts 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 you help us think about.
Where 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 in a number of rigs a small number that are working on agreements that are less than what we would consider term contracts because there are less than six months, but the majority of these are our an evergreen type agreement, where we'll drill a number of wells.
And then the agreement gets re sign and it continues on a drills a number of wells. So there's really not a trade out there or 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 the industry.
With the customers just haven't switch 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.
Alright fair enough thanks to the answers.
Your next question comes from Chris flat from Wells Fargo and your line is open.
Or somewhere in the low sixtys and probably I think the guidance implies about 41 or so in the third quarter. I think you mentioned you expect a rig count to be flat.
Going forward, what about the working rigs is that going to trend higher.
Our people can pick up rigs are you going to do you expect some of those standby rigs actually resulting rigs rolling off as the stand by period combo.
Hey, Chris I'm, sorry, but for whatever reason I think we missed about the first three or four seconds of your question. This if you don't mind repeating that help us up.
Kurt Warner Center.
That we hear you now.
Okay, how about that.
I just wanted to kind of.
On Viber working.
Guidance.
On Monday.
Awesome.
Second quarter.
Mark.
40.
So working on the third quarter.
From that.
Reported.
Right.
Yes, I think it's really just dependent on what customers decide to do in terms of activating rigs and moving on from standby back to actually working.
And.
As they as they do that that creates a lot of movement in our numbers in terms of.
Costs revenue and margin per day.
Right now, we just don't have more visibility than we've been able to give you the.
As I've said before the good news is the rig count 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 two to take rigs from standby back to actually work.
Okay.
And.
Okay.
That's correct.
I don't know.
So.
Correct.
Hi.
No.
On average.
What kind of profit.
Right.
Thanks.
Chris I'm struggling to hear your but I'm going to I'm going to answer the question. It sounds like you're asking about from track 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 you know pre coated product pricing wasn't integrate position and with this reason downturn in the second quarter.
I'd 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 a 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 create some more inventory for Frac I think there's opportunity for companies to move the frac pricing up off this floor worth that because it's certainly not sustainable where it's at and I think.
And activity increase.
I would allow companies to bring that pricing up.
Okay. Thanks, sorry about the phone problems. Thanks, no problem at all thanks.
Your next question question comes from Kurt Hallead from RBC. Your line is open.
Hey, good morning.
Good morning, Kurt.
Thanks for all the color so far.
The the follow up on my end.
The revenue progression on Frac and you gave us the.
Litigation that Frac is going be cash flow positive in the quarter. So I guess the way I look at it.
You need at least what $4 million in gross profit in track to be cash flow positive is that 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.
[music].
You know, but again you are 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 year in any of the businesses, but I'd say, especially frac and directional drilling very minimal capex yeah.
My follow up was going to be on the Capex. So I think you are guiding supplies, maybe $20 million total capex in the back half of the year. So if you were kind of split that among your segments that what would that mix look like.
Probably continues to be split about in the same percentage is what we we did earlier I mean, obviously drilling will come down with fewer actually working rigs.
You know pressure pumping.
Again, we just talked about is pretty minimal directionally pretty minimal.
The majority of what you'll see you'll be in drilling, but you'll see a little bit more.
We'll see some more obviously in pressure pumping in the back half directional I would say is very very modest.
Okay. That's it for me thanks.
Your next question comes from Marc Bianchi from Cowen Your line is open.
Thank you.
Following up to Chris' question on on Capex.
If we're going to do 20 million Bucks 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 if activity stays at these depressed levels is that something you think you can continue to do.
Yes, I'll 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 in spend so.
We can.
You know that are what it costs are under pressure pumping spread what it costs to run a drilling rig in terms of capital costs hasn't really changed its just that we were front end loaded on a lot of these expenditures, yes ill say, it's fair to say that we had been using some parts that were on the shelf.
And some spares and you know look.
I don't think it's sustainable to run at these levels for a long period of time, but you know certainly for the remainder of this year, we don't we don't see any issue.
However, we started the year the first week of January with WT trading around 62, and it was a different world and we're 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.
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 cases is a little bit different and I think our our margin for the standby rigs is not that much different than.
And when they're working for US I mean, there is some differences and there's going be some variances by basin or by customer.
But I think that to the way we approach that is little bit different.
Okay, Okay fair enough and then as as they start to think about the role of your rigs you know 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.
At leading edge day rates to the extent that there are I mean should you stabilize at this 8600 dollar level or would you think that there's a lot more downside to that maybe just help us think about the range of outcomes.
Okay.
It's a it's hard to know exactly what you know the continued outlooks going to be passed the third quarter.
In terms of everything that's going on in global economics, but if you know if you assume WT stays where it is rig count stays roughly where it is.
You know we could see some change in the margin per day, where it could come down based on 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.
Okay. That's helpful. Thanks, Andy I'll turn it back.
Your next question comes from Jay could tick up one bird from credit Suisse. Your line is open.
Hey, Good morning, guys 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 shutdown, Canada, which makes US now as a primarily a us based company.
With operation so.
In terms of anything happening out of the U.S.
I would say.
Thats 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 or any company to move assets from the us into international markets with some of the slowdowns that are happening in the international markets.
Okay, and then as as a follow up is there any cash outlay that you could quantify that you're expecting in three to threeq or fourq you related to the charges that you guys took in Q2.
Yeah, 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 in.
In two key only seven of the half million and that included most of what we paid and severance and a lot of the 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.
Yeah, I think 10 million to probably overstating. It I don't I don't have that my fingertips retina.
Okay I can circle back offline for that thanks, guys appreciate it.
Your next question comes from Chase Mulvehill from Bank of America is your line is open.
Hey, good morning, everybody I.
I guess real quick I wanted to talk about rig evolution in kind of how we think about the next stage.
Rig evolution across U.S. sector.
Basically rigs are going to have to be upgraded.
To to digital platforms that will actually enable.
Remote in 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.
Responded well they'd be able to kind of upgrade.
The rig fleet.
Comparable to what you can do.
So I think that to the good news in this story is that the rig structures that we have in our fleet are very competitive.
I think the rig thats going to be the most popular coming out of this downturn as we get into or more of a recovery mode is going to be structurally the super spec rig that's 1500 horsepower, but also has the drawworks up at the same level is 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 rigs are 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, what I would consider even a minimal costs.
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 that's the good news and what we've done hats off to our team in the engineering groups. It 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 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 a.
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.
Digital offering like how much ultimately incremental margin do you think you can capture is this like 100 dollar a day is $500 a day isn't $1000 a day like the what's the magnitude of margin accretion you think over time that you can get from this.
You know there is certainly extra margin in there for us I think the market will determine exactly how much that isn't it's 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 what we can offer.
As I mentioned earlier about 30% of our rig contracts as a mid July had you know terms in them that were different from just a plane 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 of being able to improve their efficiency and us being able to monetize our investment and.
Funded balance with the operator in that.
Yes that makes sense.
One real quick.
Follow up.
Pumping I think last quarter, you said, 65% of your 100 million cost savings initiatives were targeted towards pumping.
I'm, sorry, if I missed that 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 you know again, when we were last quarterly we're 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 there's a sizeable chunk of SGN Elsa.
It's coming out.
Some facilities shut downs.
Things like that.
That's really where we're seeing it so I would say most of them or are you know structural in nature and and again you know we should expect to see those for the foreseeable future.
Okay. Appreciate the color thanks, Andy Andy.
Thanks.
Your next question comes from Lake Dendreon from Wolfe Research Your line is open.
Yeah. Thanks. Thanks, Good morning, Thanks for going beyond here, just one focus in on your comments about fixed costs on the drilling side.
Specifically with an 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 various basins that would make sense that perhaps a lot of the the subscale providers move out of certain basins.
What would you consider optimal scale at the basin level.
And then if it makes sense from players to be exiting basins are you seeing rigs moving into the Permian fairly substantially at this point with the recount kind of depressed elsewhere.
Hi, Good morning, 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 our opex to operate a rig that we call out within the drilling company, we don't carry the soonest DNA, but its engineering. So when we're looking at engineering control systems Engineering data analytics systems. Those are carried in opex or not carried and as you know so they're they're part of that call.
Yes, and we're still investing in technology, we think it's the right thing to do for the future of the company and 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 so you've got compensation at the field level.
Got our engineering spend that's that's in there too and so those kind of things are are what I would consider.
You know 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 as single rig in a basin without a problem you know we can scale the structure of that base and around that.
We can provide support from a separate basin, if we need to you know the rig will.
We'll sit as an island in a basin if 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 in which which is really our specialty in the super spec rigs layered on with data in.
Analytics and.
Other other elements that bring technology to the table for the operators and so you know with Canada being a separate country, requiring legal entities separate payroll separate benefits separate structures.
That pose 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 the 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 makes sense I appreciate the color on and then just follow up on your capital structure, you got plenty of runway to the Twentyth and 20 nines to the degree that you generate cash over the next year or two.
Paying the balance sheet seems to be prudent but.
You know that that kind of traded down in the in the second quarter I'm just wondering how you're maybe.
Being opportunistic buybacks that debt at this point.
Yeah, you know we discuss it with the board.
Periodic Lee and you know I.
I think.
Given I mean, I think is an understatement to call sort of the activity in this quarter dynamic.
Certainly.
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.
Well, obviously look at those opportunities in discussion with our board and decide the best course of action.
Got it makes sense. Thanks.
As a reminder, if you'd like to ask a question. Please press star followed by the number one. Your next question comes from Mccarthy from ATP capital markets. Your line is open.
Thanks for taking my question a couple of questions here number one just steph.
Means type question, what is the cash and 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 the cash will I think it's going be pretty neutral going forward from working capital.
Okay.
Great and then.
Andy if oil prices should stay in this area.
Rain, just like 40 to $45 over the next six to eight months.
Do you expect to see rig count at Big gap.
You know in any any magnitude from from current levels.
I wouldn't say rig count would increase in any magnitude you might see some privates pickup some rigs there are some plays.
In our GMP actually.
Drills and some place where you can make money at 36 $38 a barrel. So there are some plays still out there. So it's you know we could have a few rigs here in there at today's oil price come back.
But I wouldn't say would come back at any magnitude I think we would need Wi Fi to move up a little bit further to really drive rig count increases and I believe that.
Early rig count increases would likely be in west Texas.
WT starts to move up further.
And then you say for the is that into 45 to $50 range to use we need a $50 plus.
I don't think you need $50, plus I think if Wi Fi moves up into the upper Fortys.
There are a number of operators that economically could put rigs back to work can be profitable drilling wells at those levels. So I don't think you have to get to $50 a barrel I think that theres certainly areas of West, Texas, New Mexico with operators that have held their land positions for long time that could be economical if we get north of 40.
$5.
Okay.
And often makes that you have on standby in the third quarter net said 17 18 rigs.
How many would see contract exploration in the fourth quarter.
Yes, I don't don't have that number in front of in but I don't think it's a big risk force either.
Okay Fair enough no you mentioned that there was a crude that.
Yes, the conducted for 40 stages a month.
Could you.
Andy comment on what made it.
Basin was that crew and what some of the characteristics of the job was it smaller stages any other technology that was being implemented a it's a pretty big number four stages per month.
It was a large number all credit the team.
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 pre planning effort and lot of credit to the operations team out in the field of working with the operator to plan, how they were going to do this and being able to.
Preplanned 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 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 one 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 you went over time move too much that's going to figure.
I think is repeatable with this particular operator in their field, depending on how they have their pad set up in the number of wells.
You know that are that are ready to go.
I don't know if you get broad numbers like that across the US just because this may have been somewhat basin specific.
So it may not be repeatable from base integration.
But it does show.
In the industry, we continue to improve the economics for the operator.
Fair enough I know that Andy you mentioned that in the bumping business you expect to be cash flow positive.
What does that mean could you Andy elaborate on that.
[laughter].
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 and in the business. It's this is a tough market we're down to operating for 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'd give a lot of credit again to our teams for getting cost out of the system and making us much leaner and more competitive.
And so I assume that in the quarter as well you have a focus active.
Yes, no change to that we just we anticipate that we have.
Increased level of activity.
Something changes during the quarter, we'll let you know the next call.
Okay. Thank you very much great quarter next car reach it.
We have no further questions I'd like to turn the call over to Anders index 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 really tough quarter lot of things they had to deal with and everybody did a great job.
Thanks, everybody for calling today.
This concludes today's conference call you may now disconnect.
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