Q4 2020 Patterson-UTI Energy Inc Earnings Call
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This will begin momentarily until then please continue to hold the line. Thank you.
The U.
[music].
Okay.
Ladies and gentlemen, thank you for standby and welcome to the Patterson UTI Energy fourth quarter 2020 earnings Conference call.
At this time all participants are in listen only mode. After the speaker's presentation there'll be a question the answer session.
Ask the question during the session who need the press star one on your telephone.
You are of any further assistance. Please press star Zero I would now like to hand, the conference of what your speech ex day, Mr. Martin Tricolor.
Please go ahead Sir.
Thank you Matti.
Good morning, and on behalf of Patterson UTI energy I'd like to welcome you to today's conference call to discuss the results of the three and 12 months ended December 31 2020.
Participating in today's call will be Andy Hendricks, Chief Executive Officer, and day, Andy Smith, Chief Financial Officer.
A quick reminder of statements made of this conference call that state the company's or management's plans intentions beliefs expectations or predictions for the future are forward looking statements within the meaning of the U S. Private Securities Litigation Reform Act of 1095, The Securities Act of the 1933 and the Securities Exchange Act of 1934 of 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 the.
These risks and uncertainties could cause the company's actual results to differ materially from those suggested in such forward looking statements of where the company expects the company undertakes no obligation to publicly update or revise any forward looking statement. The company's SEC filings, maybe obtained by contacting the company or the SEC and a bag of all through the company's website and through the SEC 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 Dot pet energy Dot com.
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 Utis fourth quarter Conference call. We are pleased you could join us today.
For the fourth quarter revenues increased for the first time since the downturn began driven by higher levels of drilling and completion activity.
We are encouraged by the higher activity levels as the industry has begun of recovery.
Based on our customer engagement, we are confident that activity levels will continue to improve.
I will now turn the call over to Andy Smith, who will review the financial results for the fourth quarter.
I'll then comment on our operational highlights as well as our outlook before opening the call of the Q&A handy.
Thanks, and good morning.
For the fourth quarter, we reported a net loss of $107 million or <unk> 50 per share and adjusted EBITDA was $29.6 million.
During the fourth quarter, we reduced gross debt by $66 $2 million through the repayment of $50 million of our term loan and open market purchases of $16 $2 million of senior notes.
The open market purchases were made at a discount to face value of resulting in a $3 $6 million gain that is reflected in our income statement as an offset to interest expense.
The reduction in gross debt combined with an increase in our cash balance over the year reduced our net debt during 2020 by $117 million to $684 million at the end of the year.
After the repayments, we only have $50 million of debt remaining that comes due before 2028, which is easily covered by the $225 million of cash on our balance sheet at the end of the year.
Capital expenditures during 2020 total $145 million for 2021, we expect total capital expenditures of approximately $135 million, including $85 million for contract drilling $30 million from pressure pumping and the remainder of spread among our other segments and general corporate.
Mrs.
Capex in 'twenty and 'twenty, one as primarily maintenance Capex focus while also allowing for technology investments and minor upgrades to our equipment to take advantage of the recovery and strengthen our position as the leader in technology and performance.
Before I turn the call back over to Andy for the first quarter, we expect SG&A expense of approximately $23 million, we expect depreciation depletion amortization and impairment expense of approximately $148 million for 2021, we expect an effective tax rate of approximately 21%.
Lastly, we will be paying our quarterly cash dividend of <unk> <unk> per share on March 18th 2021, the holders of record as of March four 2021 with that I'll now turn the call back over to Andy Hendricks.
Thanks, Andy.
In contract drilling our average rig count for the fourth quarter improved to 62 rigs from 60 rigs in the third quarter.
The proportion of rigs that were idle, but contracted decreased to 16% in the fourth quarter from the 28 per cent in the third quarter.
Our rig count improved to 65 rigs at the end of the year of which five rigs were idle but contracted.
Average rig margin per day during the fourth quarter was $7770, which exceeded our expectation.
Relative to the third quarter average rig revenue per day of $20210 was negatively impacted by lower day rates and the absence of any lump sum early termination revenues in the fourth quarter.
Average rig cost per day increased to $12440 due primarily to a smaller proportion of rigs that were idle but contracted compared.
Compared to the third quarter.
At December 31, 2020, we had term contracts for drilling rigs, providing for approximately $300 million of future day rate drilling revenue.
Based on contracts currently in place, we expect to average 42 rigs operating under term contracts during the first quarter at an average of 34 rigs operating under term contracts for 2021.
Looking forward first quarter drilling activity is expected to improve averaging 69 rigs for the first quarter of which an average of five rigs are expected to be idle, but contracted.
With a smaller proportion of rigs that are idle, but contracted during the first quarter average rig revenue is expected to increase to approximately $21000 per day and average rig operating costs is expected to increase to approximately $14500 per day also due in part to the reset of payroll taxes in rig reactivation.
The expenses.
Turning now out of pressure pumping we average seven active spreads during the fourth quarter up from five active spreads in the third quarter pressure pumping revenue for the fourth quarter increased to 79, and a half million dollars from $72 million in the third quarter.
Gross margin decreased to $4 $1 million.
While industry completion activity in the Permian increased during the fourth quarter in the northeast, where we have a strong presence industry completion activity decreased significantly and remained at this lower level as we entered the first quarter.
As a result, we are relocating one of our dual fuel spreads from the northeast to Texas, where it has dedicated work.
We expect low utilization of our active frac spreads in the northeast until later in the quarter when the plans of our customers suggests the increasing activity.
We expect the average seven active spreads during the first quarter, including the spread that will be idle for a period of time, while moving to Texas. Despite.
Despite lower activity levels in the northeast pressure pumping revenue and gross margin in the first quarter of both expected to be similar to the fourth quarter.
Looking forward, we are encouraged by the increase we have seen in the rig count and expect we will see further growth in completion demand.
Turning now to directional drilling revenues increased 64% during the fourth quarter to $16 $9 million outpacing the growth in the horizontal and directional rig count during the quarter as we continued to gain market share in this business.
The market share increase was aided by the enhanced performance of our new technology, the Mercury measurement, while drilling system and the new impact directional drilling motor sizes, which were introduced in early 2020.
With better fixed cost coverage and the benefits of the cost reduction efforts implemented in 2020 gross margin improved in the fourth quarter of $2 $2 million or 12, 8% of revenues from half a million dollars or 5% of revenues in the third quarter.
For the first quarter, we expect directional drilling revenue to increase approximately 15% to $19 $5 million with gross margin of approximately $2 $2 million.
Turning now to our other operations, which includes our rental technology and E&P businesses.
Revenues for the fourth quarter were $8 $9 million with the gross profit margin of approximately 10%.
For the first quarter, we expect other operations revenues to improve to approximately $10 million with the gross profit of approximately $2 million.
Our other operations include the Technology Division current power.
This electrical engineering and controls division continues to broaden its customer base into other sectors, such as marine and industrial micro grid.
Marine products are now growing to be the largest portion of this business. As an example of the type of projects. We are in the process of completing the delivery and installation of the full electrical controls for the propulsion system of the first new cruise ship built in the U S. In recent years.
Also our team has experience in products for micro grid controls and various industrial applications and we expect demand in this sector to continue to grow along with the expanding renewables and smart grid electrical systems industry.
The start of a recovery is an encouraging time, the oilfield and especially of Patterson UTI like.
Like the rest of the industry. We are looking forward to increased activity levels and bringing back more employees and we are also encouraged that we were coming out of this downturn stronger than before similar to how we of emerge stronger from every other downturn of the company's history with improved liquidity reduce debt and a greater technology position.
We are very well positioned both financially and operationally and our investments have made us a leader in technology and performance.
In 2020, we reached several technology milestones from which we expect to benefit during the recovery.
First we strengthened our position as a leader in alternative fuel technology with the commercialization of our eco cell lithium battery hybrid energy management system.
This unit is capable of efficiently displacing one of the gen sets on a rig to reduce both fuel consumption and emissions.
The value of this technology is maximized when used in combination with our cortex power management system and our dual fuel engines is the natural gas substitution rate can be optimized with.
With an increasing interest among customers in ESG solutions, we are very excited about this technology.
We also commercialized our cortex key data analytics device in 2020.
Of this edge server device installed at the well site allows for the streaming of high frequency data, which can be combined with the analytical power of our pizza and plus performance center to drive informed decisions.
And improved efficiency.
We commercialized a remote measurement while drilling operations during 2020 and have started to build significant experience with 69 wells were more than a million feet of wellbore drilled using remote M. WD operations with a more efficient cost of service delivery.
We also commercialize our cloud based and remote operation Hi, Fi NAV Wellbore placement service in 2020, including automated data transfer from the well site.
Hi Fi NAV is the one of the kind of algorithm for improving the knowledge of the wellbore position, while drilling both horizontally and vertically thus reducing geologic uncertainty in real time.
In 2021, we expect to commercialize our cloud based high five guidance, which takes the output of Hi Fi NAV.
As well as Geo steering target changes and calculate steering decision to ensure the wellbore stays within the producing zone, while optimizing rates of penetration.
We have several other exciting technologies that we're actively working on and are excited to bring to the market in 2021.
With that we would like to thank all of our employees for their hard work and Valiant efforts through a very challenging time, both in our industry and in general.
Manny we would now like to open the call to questions.
Yes, Sir as a reminder to ask a question you will need of press star one on your telephone to withdraw your question press the pound key.
Your first question comes from the line of Sean <unk> with J P. Morgan.
Thank you Hey, good morning.
Morning, Sean.
So Andy and Andy of something we can start talking about cash flow for a little bit.
So the term loan pay down.
And the debt repurchase makes sense.
We also consumed more cash than the generated beyond that in the fourth quarter.
Activity starting to ramp could we just maybe I think the Capex guide also.
Makes sense based on our activity assumptions.
Can we just maybe talk about.
Sources and uses of cash maybe as we ended the year and going into 'twenty one.
As we think about working capital, maybe a use of cash a little bit as activities moving higher.
Cash taxes, even divestitures of any of the pieces of what you're thinking about on cash movement.
Now and the end of the year.
Yeah. So.
We built a little bit of working capital in the fourth quarter and that was really more of a timing issue.
More than something that I would say is.
The trend I do think as we go through 2021.
We will probably be a little bit higher in working capital not significantly.
You know, we do always look at our again, because you talked about divestitures, we're not talking about any line of divestiture, but certainly we look at our.
Our portfolio of assets and we are constantly looking at things that were you know selling whether their properties or older equipment or things like that so you'll see some cash from that cash taxes I wouldn't expect much in.
In the year.
So really you know we kind of always think about.
Again in kind of a flattish working capital type of environment.
You know an EBITDA less less.
Less Capex and then you know interest.
Spence with some of the noncash items that are already embedded in EBITDA, sometimes usually generally wash out. So that's kind of how we look at our free cash flow for the year.
That's really helpful. Yeah, I think that makes a lot of sense and then I wanted to touch on the.
The lithium battery.
<unk> and dual fuel optimize fleet. So we put all that together and just looking to get some more granularity on the opportunity set there.
So things like <unk>.
Are you able to get a premium in the market for these what is the fleet mix look like today I assume it's pretty low in terms of.
Of the batteries today by dual fuel how much does that make up of a mix.
The Capex budget. This year is that account for any material dual fuel conversions.
I guess then that is also.
Is this the topline story in terms of <unk>.
Megan is the bigger piece of the fleet or is it really is about of bottomline being competitive in the market and doing some piece of the lower cost or lower capital expense.
I think for us it's a mixture of increase.
The increase revenue, but also staying competitive and increasing market share. So when you look at the dual fuel we do this from both drilling rigs and pressure pumping.
All of the drilling rigs and we've had a number of our rigs kitted up for dual fuel for years.
Some customers use of that Optionality, some do but it's there on a number of our rigs already so I don't it anticipate are the.
There is really any spin there on the Capex side.
In the pressure pumping we're one of the leaders in dual fuel we've been doing that for years as I mentioned one of the spreads we're moving from the northeast of Texas is already kitted up for dual fuel.
But we will add some more dual fuel in pressure pumping, but the it's.
It's already built into the Capex plan.
The real interesting story is the eco cell and the the lithium battery storage energy system that we have there.
And how it can control the engines in auto switch off engines and in control of the loads on the various engines of the balancing that out with the energy draw of out of the lithium battery storage and.
We have some we have one working in the field today that we've been field testing and we've commercialized that system. We have another one that it'll be in the field shortly and we have battery orders to get us through the year to build what we expect will be a fairly strong demand of these and I don't want to throw any numbers out yet, but we've already preordered battery.
<unk> to come in to be able to build these eco sales and that's built into the Capex budget.
And just last thing there are you able to quantify that difference in terms of like just let's say on a new build fleet or something just to quantify what a traditional set looks like versus what this would look like just to level set for people.
Yeah, I mean, the eco sales for the drilling rigs and so there is there is value for the operator, there when we're running that it reduces fuel consumption and so you know and there's a cost to build it. So we are able to charge to recoup that cost and get a return on the investment when we add debt to a drilling rig.
Great. Thank you.
The next question comes from the line of Ian Macpherson with the company of Shannon.
Thank you good morning, I wanted to ask a couple of questions on your Q1 outlook both for activity.
And for the components of your of your margin guidance.
Youre activity today on the website 70 rigs so you talked about.
Activities can continue to improve but your Q1 guidance it looks like it's around where you are today.
So I just wanted to get your thoughts on where you see.
Yeah.
The rate of improvement in the rig count.
As we go through the quarter or do you feel like we're nearing the top.
Or a temporary top anyway, and the plateau from here or could there be some element of conservatism in that 69 rigs for Q1.
So the way the math ends up on the 69 rig projections for Q1, yes. We're at 70 on the website right now, but we only average 67 in the first month of the quarter.
So it's likely to be roughly flattish for the rest of the quarter, but it's not a top not of plateau.
Just where the quarter is going to land as we look forward for the rest of the year I anticipate we'll be putting up more drilling rigs, but that's just where the quarter lands in terms of the math and the count on the projection.
Okay. Thanks, Andy.
And then I think you said your day rates should be at 21000 in the first quarter, so that would be.
That would be up from the past couple of quarters.
What's driving that and then if we get better cost absorption.
After Q1 with the reactivation and payroll ex.
<unk>.
You mentioned that are pushing your cost up in Q1 is there do you have some visibility towards of troughs in cash margins in the first quarter and maybe some upside beyond Q1 or is it too early to necessarily call that.
So what we said on the last call was that we thought that we would see of margin bottom for our business sometime around Q4 Q1, our visibility right now as of this is likely Q1 and that we should see improving margins throughout 2021 based on based.
Based on not necessarily where you know W. T is trading today, but based on where W. T. I was trading earlier in the quarter. So I'm actually somewhat encouraged a little bit upbeat and if W. T I.
Holds where it is today then there maybe even a little more upside than the way we had of viewed earlier in the quarter, but I would say that you know like I said, our view is that Q.
Q1 is likely the bottom for margin and we should see some improvements in margins throughout the year from here.
That's great. Thanks, any other Matt yeah.
The improvement.
Your.
Sorry go ahead.
I was going to say I assume that the average cost go down with better absorption as part of that calculus right.
They should over time, Yeah, I would also say to your first part of your question about day rates coming up.
That's almost entirely a mix issue as we have fewer idle, but contracted rigs work.
Included in our rig count in the first quarter relative to the fourth quarter.
Got it. Thank you gentlemen, appreciate it.
Sure.
Your next question comes from the line of Christopher <unk> with Wells Fargo.
Hi, good morning.
The morning, Chris.
Maybe pushing out of pressure pumping here for a minute.
I guess can you help us think about the impact.
The impact of just having the first quarter. If you were to exclude that idle time.
Would there be more of them and in gross profit or can you help us maybe think about the exit rate in the first quarter and maybe you know wrapped into that has there been any improvement in pricing within pressure pumping so far this year.
I'll work backwards on that there's certainly been no improvement in pricing.
And we don't anticipate any improvement in pricing in the first quarter.
I think that as rig count continues to move up through 2021, there will be an opportunity to push pricing in pressure pumping later in the year. So we're somewhat encouraged there, but it just hasn't happened yet the especially with what we saw in overall industry activity levels in the fourth quarter of the northeast It came down.
Fairly quick it came down a significant amount and as you know we of a strong presence up there in the northeast as well as we do in Texas and so we made the decision and we're able to work with an operator in Texas and move one of our dual fuel spreads out of the northeast and into Texas and the interesting thing for us is debt.
Dual fuel in pressure pumping is proud of and we're primarily a rule of historically been in northeast phenomenon, because you're in the gas markets, but we're seeing more operators in Texas.
Trying to deal with the gas production that they have in their fields and consume it are starting to look at and switch the dual fuel in Texas. So since we have those fleets we have that equipment. We're encouraged by that opportunity to build the move that down there, but because of the decrease in industry activity in the north of Houston decrease in our activity.
There's a lot of moving pieces in the numbers for both Q4 and Q1. So we're we're projecting that we're going to hold our spread count flat and basically a similar financials revenue and margin to Q1 is what we had in Q4, just because of the movement and activity.
As I mentioned in the earlier in the northeast, we don't anticipate activity improving until the end of the first quarter and that's just based on discussions with the customers.
Okay. That's helpful. Thanks, and from my second question.
I guess you have a lot of the large.
Of private E&ps in your customer base of decent part of your customer.
Customers I guess.
Do you have of you on the activity going forward from here on a public versus private basis do you think it's pretty consistent or do you expect more growth.
From one versus the other.
I think theres two components of it I think one is the reaction time of the privates versus the publics and that'll play out similar to what it did last year, where the privates and the smaller publics can move faster than the large publics are the large publics have been slow to react and in some cases are still releasing.
The rigs and the privates and the smaller more nimble publics have been moving quicker to reactivate rigs too.
Grow activity and the numbers you've seen in the data but also.
Have discussions with us about what they want to do later in the year. So it's really the large publics that are that are moving slow in this process.
Alright, thanks for taking my questions.
The next question comes from the line of Mike Sabella with Bank of America.
Hey, good morning, everyone.
Good morning, Thanks for taking the call.
I'm wondering if you could just kind of start just pick apart the pumping guidance a little bit more.
Are you able to help.
Help us understand when.
When that fleet starts working down in Texas.
And then.
As we think about the northeast.
Kind of a percentage of.
What you all are.
Our earning can you help us understand the magnitude of that business.
And then if there are any cost some of that fleet down the Texas.
So.
The fleet will take approximately two weeks to a move down to Texas from the northeast from the time it leaves.
Earning revenue in the northeast to the time it starts earning revenue in Texas.
And Theres no real significant cost other than fuel and some component changes that will make for the activity in the south.
The northeast, but I would say overall costs are fairly minimal.
We're certainly seeing a shift here lately in the amount of activity not just us but the industry.
Where you know the northeast was busier earlier in the year busier than the third quarter and then you know had a big slowdown in the fourth quarter.
And with US moving of spread then.
Sure.
We're down to a shifting mix and so the majority of our work is going to be in Texas and then we'll see how that plays out later in the year, but it's clear that GAAP.
Gas operators in the northeast are really trying to manage of.
The gas market up there as best they can and not push too much gas into that market.
Got it and then switching to rigs.
In the press release some of that.
<unk> 34 rigs under contract. This year can you kind of give us the split of.
You know what you know what proportion of those were pre COVID-19 and what proportion of our post COVID-19.
I don't have that information off hand in terms of the timing of the contracts.
I'd say a fair number we're still pre COVID-19, we're still gonna see of roll off of rigs that are pre COVID-19.
Been signing some bit of a mix of these.
When you look at the rig fleet that we have today, it's a mix of pre COVID-19 contracts contract signed during Covid and then shorter term work that might be six months or less so.
It's a mix of all of that today.
Got it and it is the the term contract that you are getting today are those close to where spot is there.
Is there any difference.
Can you say it again.
The term the term contract Youre getting today are those close to where spot sits or are there is there a difference between those two.
I would say the term contracts, we're getting today are close to what the spot market is.
When we sign rigs today on on term contract, where typically shy of signing is short of term as we can negotiate because we think there's upside later in the year.
Got it thanks for taking my questions.
The next question comes from the line of Scott Gruber with Citigroup.
Yes, good morning.
Good morning, Scott.
So with the upturn in the market here I imagine that customers don't want to lose the efficiencies that they've gleaned over the past 12 18 months has happened historically the those would reverse during the upturn and now customers that obviously have some more cash coming in the door.
The Andy can you talk about your ability to.
You could potentially expand your the ancillary services.
Your software and of that sales within drilling or are those conversations starting to accelerate here.
Yeah, and I would say that some of the successes that M. S. Directional is seeing an increasing their market share and growing faster than the rig count is due to the fact that.
We have a low.
Very large drilling contracting company that can open a lot of doors for that so we're certainly seeing synergies.
From that you don't want to take away from what they're doing at M. S directional because of doing a lot on their own. The service quality is very high today, they're providing high levels of efficiency for customers, but we're seeing more customers who look at our rigs also look at M. S directional.
And.
Following on from that Theyre looking at.
How can they layer in some of these are interesting software services, such as Hi, Fi NAV, which is a it's of.
Software cloud services remote operations and.
As a lot of benefit in terms of Wellbore placement and improving production. So I would say all of these things are starting we're starting to see more pull through from from all of these as we build out these levels of technology and connect the dots between the various services.
Got you and then just turning to Frac.
Are you starting to see any inflation.
N frac of realized sand and any sand inflation will get passed on the.
The thing about trucking or chemicals.
Is there any inflation starting to creep back into the system on the FX side as we get going again.
I think the one area of that stands out as trucking. It's just a it seems to be harder to find drivers in the Permian and so moving sand is creates more challenges there from a trucking standpoint, and there's been some inflation in the trucking costs.
And.
How quickly can you pass those on the customer.
Do they just eat debt.
You know in the challenging market like we're in I would say the ability to move that is relatively slow only because operators today want us to quote the jobs with some of these costs all baked in so we try to manage the contracts with the suppliers back to back at the same time, there may be times during certain contract. So it's a little bit.
More challenging, but I'd say for the most part we try to manage the back to back.
Understood appreciate the color. Thank you.
Your next question comes from the line of Taylor Zurcher of Tudor Pickering.
Hey, good morning, and thank you.
My questions are largely follow ups, but I think the importance I'll ask them anyway. The first is on.
On the pressure pumping side of the business.
And clearly there was some white space are quite a bit of white space on the calendar in Q4 of your your average active spread count was up 40% sequentially with two extra spreads, but the revenues are much lower and so clearly the days of work went up 40% sequentially can you can you help us understand what the utilization of is for those.
Seven active spreads as you define them, where what the utilization look like in Q4 and then.
How many of those fleets are actually in the northeast today.
At least we're in the northeast in Q4, and how many of the fleets are going to be in the northeast from Q1.
So it's.
It changes month to month.
But I would say, we definitely had a fair amount of white space in the calendar, mostly driven by the northeast, but also you know a few other customer specific issues in the fourth quarter. So you know I look at those as relatively transitory, but it ends up looking similar in the first quarter as well because we're moving of spread down because we're waiting on the operators too.
The pick up activity in the northeast.
You were to try to quantify the white space in Q4, it's going to be roughly equal for us in Q1 because of all of those factors.
I don't know if debt that helps you out.
Yes, it does it end.
Can you give us a breakout of of where your spreads are located today, whether it would be Texas first of the northeast.
So we've got two working in the northeast.
With varying degrees of white space in the calendar and then the others are working in Texas Okay.
And my follow up is on the contract drilling side of the business.
I heard you correctly it sounds like you expect the margins to bottom here in Q1, and there is some payroll taxes that negatively impact margin that will go away in Q2, but.
That's correct can you help us understand what was driving the the margin bottom in Q1 as it.
Better fixed cost absorption.
The drive most of that margin improvement over the course of the year or do you also expect the debt.
The average day rate that.
Of that you report each quarter to be relatively flat, if not having bottomed in Q1.
Yeah, Let me, let me clarify that so I think that EBITDA is ball bottoming for the company in the first quarter and then continues to improve through the year, we're still going to have some decrease in percent margin as of percentile as we have some rigs roll off preexisting contract pre COVID-19 and into today's market.
And so we'll see we'll see some decrease in percent margin, but overall, we should see growth in EBITDA from where we are today.
Understood that makes sense thanks, guys.
The next question comes from the line of Connor Lynagh with Morgan Stanley.
Yeah. Thanks, just.
Just the higher level one from me here, we've seen a fair bit of activity on the on the pressure pumping side of the business in terms of your some of your competitors consolidating or rolling up smaller competitors of few transformative deals.
Generally speaking, we've kind of heard from your guidance and others talking down the the merits of land rig consolidation, but I guess my question is with the.
Where we are today and.
The sort of prospects for Capex growth in the U S E&P industry why.
Or is that not more top of mind.
What's your sort of thinking around the potential consolidation there.
I think in the land rig business and the way we view it is when.
And when we view the land rig business, we're looking at the Super spec apex rigs that we operate.
And so it's just not clear to us the you need a lot more consolidation.
The.
What we've seen historically as you know the rig count starts to move up the pricing starts to move up.
And I think that we'll see leading edge.
Day rates move up later in the year as the rig count moves up.
So I'm not sure that the industry needs more consolidation of the way other sectors of oilfield services need consolidation.
That's fair I guess since we're on the topic of pricing.
Some comments in the press release of of.
Looking forward pricing in the future.
I take from your comment there, we haven't seen it yet but.
But could you maybe just characterize I guess theres sort of the push and pull of U.
If you if you increase your volume you absorbed some better fixed costs and improve your margins of that way.
Think about the the likelihood of it or the desire to raise prices versus spot rates for new term contracts.
We're definitely focused on margins and maximizing those margins wherever you can whether its the drilling rigs, it's pressure pumping or it's directional drilling et cetera, and so we're going to try to get some pricing.
Power when we can you know it's one of the reasons that were still flat on Frac spreads. We just don't see a need to add more capacity to the market, we'd like to see the pricing move up in the market before we try to push more frac spreads into Texas and so we think that there may be an opportunity to move pricing up later in the year in pressure pumping because that's.
Where we need it the most.
And as I said in drilling I think as the rig count moves up later in the year. There is an opportunity for the day rates to move up from where they are at spot.
Alright fair enough. Thank you.
Thanks.
The next question comes from the line of Deb Zack.
With Coker Palmer.
Hey, guys. Thank you for taking the <unk>.
Okay.
I wanted to make sure I understand it correctly.
The EBITDA for the company troughs in non QM and improved but not specifically the laggard margins ex gas.
Yes, that's fair.
As I said I think.
Where we are and the way, we look at 2021 and what could potentially happen.
Is that EBITDA is bottoming in the first quarter margin could still come down in terms of percent margin is.
As rig.
It rolls off and then.
The it could change later in the year, depending on what pricing does and how many rigs we're operating.
Okay.
The.
If you think about it.
How are you thinking about how the U S rig count moves from here so.
Please enter price may still have.
Public guys, who will aggregates.
Can you talk about how much visibility you have and like how you see beyond <unk>, how the rig count could shape up.
Well I think what's interesting when you look at the rig count is the number of rigs that are operating in the industry of the number of rigs that we're operating today is really based on where commodities were trading several months ago. So the.
Of the activity that we have today is based on plans that were put in place two and three months ago and theres a bit of a shift in the commodity price. So that's going to change the cash flow for our customers, but we just haven't seen that move into actual activity and it'll be several months before we do but I'm encouraged based on where commodity prices are trading debt.
The rig count has the potential to move up later in the year.
Okay, and maybe switching to pressure.
Just if you think about holding the pressure pumping.
Pricing flat for a moment.
I assume it's going to be flat.
About five to 6 million EBITDA per fleet in <unk>.
And the declining one cubic like at current pricing is that five to 6 million EBITDA per fleet.
Thinking about your profitability on average.
Yes, I would say when it comes to pressure pumping, it's really about trying to align with customers who can maximize the overall efficiency of the operation and maximize <unk>.
Stages per month stages per quarter, and certainly we were challenged there in the northeast and I think the whole industry was when activity came down.
At the at the magnitude of the did in the fourth quarter of the northeast and then we have this transitory situation where the activity in the northeast is still going to be low starting off in the first quarter and maybe pick up later in the quarter and then we're moving assets out of the northeast into Texas. So theres a lot of things that are going on.
But the real key is to try to find the operators who can keep this equipment busy there is theres a number of operators out there that are even struggling to be efficient in their own processes because of their own budgets their own cash flow. They want to work on a certain number of wells and then they want to take breaks and that's not efficient for the MSR efficient for us or the.
The industry in general.
And so as commodity prices have moved up in cash flow improves I think theres an opportunity for operators to be more consistent with the work and that helps us and it helps the industry.
Got it.
Thanks for taking my question Dana.
Your next question comes from the line of Blake Gendron with Wolfe Research.
Okay.
Yeah. Thanks, good morning.
I wanted to circle back on the game theory with respect of term contracts here for a second and maybe ask the question of different way than some of the others.
The commentary about you lock in the shortest.
Duration possible to maybe capture some upside.
Moving forward that makes it sound like maybe your customers.
Customers aren't really willing to acquiesce the pricing.
Even if that meant locking in longer term. So first of all is that true and then.
To get more term is there a percentage pricing improvement that you kind of have locked in or you you would ideally like to see and then if we stay in this grid lock I mean are we just presumably going to see six month of shorter term in perpetuity until the rig count gets to a certain level. How do you think I guess about the.
Your elasticities of pricing and also term contract duration.
I think pricing is still competitive out there in all of the services, including the drilling rigs.
That.
We're all thinking that Theres, some upside and I believe there is based on how commodity prices have moved over the last few months and I think that operator cash flow will improve and then activity will translate to the higher rig count so.
You know I think there's upside and so we we don't want to get ourselves locked into long, but the the discussion about how long were willing to lock in a term.
You know, it's not just pure math I mean, certainly we'd like a higher price if we're going to lock in a term today for a longer period, let's say a year or more but it might be that it's with a particular strength strategic customer who keeps us busy there there might be several reasons, we might do that other than just of a percentage increase over the price. So it's it's not just about the math.
But.
In general we're trying to keep the terms relatively short because we think we have some upside.
That makes sense.
Interesting commentary about the micro grids and maybe participation in the renewable and smart grid build out over time I would imagine that's small but can you give us an idea of what the opportunity set is here in the near term and.
Maybe if you have an idea of growth or Tam moving forward or is it just too nascent lumpy and early to tell at this point.
I think it's let's start with its small it's not big dollars within the scheme of what we do I don't think we know the full potential that's out there. The marine business has been interesting for us we've been doing a number of various vessels over the years.
And this cruise ship was one of the larger projects. We've had and we were very pleased that the team was awarded this project. It shows the confidence that shipbuilders have and the types of systems that we can build and install on these vessels. So that's very interesting and it.
This kind of award can lead to a larger awards in that sector in the future in terms of industrial micro grids. This is all new and fresh in the U S.
You see a little bit more in Europe, but this is something that's still pretty new.
And I don't think any of us can really project, what that's going to mean or what that's going to mean for our current power division, but we do a lot of interesting things that are custom engineering for specific applications and so our ability to customize differentiates us from some of the larger companies that we compete with.
Here in North America, and so it's why we're in discussions with various companies on various projects today because of our ability to tailor things based on the industrial projects.
Got it and one more quick one if I can sneak it in some of your Mark some upgrade capital here to the dual fuel you've been a leader in that space for a long time I'm wondering if you could help us think about maybe newbuild economics at this point, even if youre not necessarily going to do it yourself you have a good idea of what pricing looks like today to get a new dual fuel.
Spread 50, K versus what it was a year ago and maybe comment on <unk>.
Relative barriers to entry for those who aren't necessarily.
Current in terms of the Nextgen Frac technology.
Yeah, Theres no newbuild economic today than anybody buying new equipment is just making a bed in the hope on the future because of the economics just don't exist.
You know, there's certainly no point in investing in a full frac spread right now are adding capacity to the market. I think there are small things you can do you can do upgrades you can add dual fuel kits on engines, you already own and those kind of things that can make sense, but full spreads is very difficult to justify economically.
Yes, if your question was around the cost of of.
Procuring that equipment it has come down a little but still we don't believe that the market economics makes sense for.
We're putting in new equipment.
Okay.
That's helpful. Thanks, guys.
Next question comes from the line of Mike Hart side, with a TV capital markets.
Thanks for taking the call.
Could you talk about.
Drill pipe inventory.
Are you buying growth by bank now you have enough in the inventory and when do you think you'll be in the market.
Yeah.
I don't want to get too many suppliers excited but we're buying drill pipe. So the demand is there for us. It's a it's a great rental business. It's part of our Capex budget. There's good paybacks on that so yeah, we're actually adding drill pipe.
Okay. Good.
And then of intense of your of maintenance Capex for the drilling rigs and pumping could you maybe provide some guidance day of what's it running it.
On the peripheral basis.
Yeah. So on a per rig basis, we're still kind of in that 750000 of $1 million range per rig per active rig and then on a per spread basis worried about $4 $5 million per spread and pressure pumping Inc.
Inclusive of fluid ends.
Okay.
And fluid ends of running at what like $1 million or so.
Year.
Yeah, a little a little north of that but not much there of come down.
We're doing a better job of.
Of maintaining them in the field and getting more useful life out of them.
So our fluid end.
On the usage has come down some and so so has our maintenance expense.
Now all of these numbers were pumping, especially at the sustainable number as longer term or do you think this is more like of one one year of 18 months kind of number and then it may go up.
No we think they are sustainable.
We should be at a at a relatively normalized type spend level per per fleet. This year.
Andy I know you.
Both of your of major businesses drilling and pumping but.
Just thinking of.
In the second half do you think.
Which business grows more in terms of top line.
From from the from the first half levels.
I think we will see.
In our case may be different than others, but I think we will see our drilling business grow at a faster pace on the topline and that's combination of activity and maybe the possibility of some pricing power later in the year on the pressure pumping side, we're just very cautious about activating spreads we want to see some pricing increase.
There before we really push activations on the spreads.
Okay.
So maybe you want your EBITDA per crew to be before you would.
Reactivate the true right now it looks like and if you once you take out the cost of the.
Fluid ends the really isn't any EBITDA.
True.
Yeah, It's I mean, it's running pretty tight vs. It's still an oversupplied in challenging market today.
And so we'd like to see that move up a little bit from where it is we want this business to be accretive our projections are that it's accretive for the year.
So we'll just continue to evaluate it on a case by case basis basis, as we look at the various projects.
So does it the EBITDA per crew needs to be above maintenance capex for you to activate.
Correct.
The minimum debt, okay and to get there do you need price increases are just on.
Utilization you can get there.
We can get there on utilization because as I was explaining earlier you know with the slowdown in the northeast in the fourth quarter and then that.
No not increasing activity in the northeast of later in the quarter. Then you know theres some activity challenges there so that's going to improve the financials.
When activity improves in the northeast.
So with the spreads that we're working we're above the cost of.
It takes the work these spreads.
But we are certainly challenged by activity late in 2020.
But when it comes to reactivation, you know theres some cost for reactivation and we want to make sure we cover those costs as well.
Yeah.
And then in terms of self heal hydraulic horsepower dedicated per crew is that an NAV of the designing around 50000.
It's a little bit higher you see us doing more work in the Delaware basin, so that consumes more horsepower in the Delaware.
Okay.
Great. Thank you Lee and my Thanks, Andy.
I appreciate the car.
And your last question.
Comes from the line of John Daniel with Daniel Energy Partners.
Hey, guys. Thank you.
Just one question for now the yet.
The northeast.
Just your visibility into the year.
Recovering to the levels that you.
She was that in 2020 do you see of gone higher just your thoughts there.
My discussions with operators in the northeast.
Leave me to believe that they are concerned about the price of natural gas in terms of over producing up there and negatively impacting it and so.
They're trying to keep their activity.
The levels in check.
So that they don't overproduce in the northeast.
The I think of lot of what we saw in terms of Q3 going into early Q4 and activity levels was.
Going back to wells that were in the inventory and bringing those online.
When we look at the rig count in the northeast and that's probably a better proxy for what's going to happen in completions, we see the the rig counts relatively flat.
So we're not looking for a huge increase in activity in the northeast.
We do have some specific customers that will increase activity with us later in the quarter.
But our rig count projection of if there is relatively flat.
And when they come back with the little bit more activity does that necessitate reactivated in the Kruger Linda.
Some of the white space or moving the crew back from Texas, I'm, just kind of size of managed.
It's really just filling in white space and will be busier on a stage per month basis.
Thank you for including.
Thanks.
Yeah.
There are no further questions at this time.
Alright, well, we want to thank everybody for joining us today and again, we want to thank all of the employees of Patterson UTI for all of the great work, they're doing and we'll see you next quarter I appreciate it.
And this concludes today's conference call you may now disconnect.
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