Patterson-UTI Energy Q1 2023 Earnings Call Transcript

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Provided by Quartr
April 27, 2023

Key Takeaways

  • Solid Q1 financial performance with net income of $99.7 million and adjusted EBITDA rising to $256 million, demonstrating strong cash generation.
  • Returned capital to shareholders by repurchasing 5.6 million shares for $73.6 million and $9 million of debt for $7.8 million, and plan to return ~50% of free cash flow via dividends and buybacks.
  • Contract drilling demand remains strong for Tier 1 super-spec rigs, with Q2 rig count down modestly but margins set to rise on renewals at current rates and expected rig count recovery in H2.
  • Pressure pumping saw spot market softness and weather disruptions in Q1, with calendar white space increasing and Q2 revenues and margins forecast to decline to ~$277 million and $61 million respectively.
  • Maintained capital discipline by lowering full-year 2023 CapEx guidance to $510 million (or $480 million ex customer-funded), prioritizing cash flow and profitability over activity levels.
AI Generated. May Contain Errors.
Earnings Conference Call
Patterson-UTI Energy Q1 2023
00:00 / 00:00

There are 11 speakers on the call.

Operator

Thank you for standing by. At this time, I would like to welcome everyone to the Patterson UTI Energy First Quarter 2023 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question and answer session. Thank you.

Operator

Mike Frickmamer, Vice President, Investor Relations, you may begin your conference.

Speaker 1

Thank you, Cheryl. Good morning. And on behalf of Patterson UTI Energy, I'd like to welcome you to today's conference call to discuss results for the 3 months ended March 31, 2023. Participating in today's call will be Andy Hendricks, Chief Executive Officer and Andy Smith, Chief Financial Officer. A quick reminder that statements made in this conference call that state the company's or management's plans, intentions, targets, beliefs, expectations or predictions for the future are forward looking statements.

Speaker 1

These forward looking statements are subject to risks and uncertainties as disclosed in the company's SEC filings, which could cause the company's actual results to differ materially. The company undertakes no obligation to publicly update or revise any forward looking statement. Statements made in this conference call include non GAAP financial measures. The required reconciliations to GAAP Financial Measures are included on our website, petenergy.com, and in the company's press release issued prior to this conference call. And now it's my pleasure to turn the call over to Andy Hendricks for some opening remarks.

Speaker 1

Andy?

Speaker 2

Thanks, Mike. Good morning and thank you for joining us today for Patterson UTI's 1st quarter conference call. We are pleased to report another quarter of solid financial results. The exceptional results in our Contract Drilling segment Demonstrate our ongoing ability to capitalize on the robust demand for Tier 1 super spec rigs and the renewal of drilling rig contracts at current rates. During the Q1, we continued to return capital to shareholders and strengthen our balance sheet at the same time.

Speaker 2

We repurchased 5,600,000 shares of our common stock for $73,600,000 and we repurchased $9,000,000 of long term indebtedness for only $7,800,000 Our pace of share repurchases Accelerated as we believe the price of our shares are disconnected from the underlying fundamentals of our business and represent an outstanding opportunity. Softness in natural gas prices, along with uncertainty regarding the future trajectory of oil prices, led to what we believe to be a transitory and mid cycle pause in activity. However, we expect relative stability in the rig count for Tier 1 super spec rigs As operator budgets closely align with current crude oil prices due to capital discipline and current crude oil prices Continue to support ongoing drilling and completion activity. The decline in the overall rig count to date during the Q1 has been both nuanced And bifurcated. Lower spec SCR and mechanical rigs were primarily released and the net result was the high grading of the overall industry rig fleet driven by various operators.

Speaker 2

This high grading, which positively impacts well economics, has supported demand across the industry for Tier 1 super spec rigs and maintained a high level of utilization. Looking forward, we expect that improving market fundamentals for oil will positively impact drilling activity levels, Although near term drilling and completion activity may be modestly affected by current natural gas prices. In contract drilling, we will continue to capitalize on our position as a leading provider of Tier 1 super spec rigs and we'll strategically focus on profitability and cash flow over activity levels. We are confident We can best help our customers improve their drilling economics through our continued focus on operational excellence. By focusing on the efficiency gains offered by Tier 1 Super Spec Rigs and integrating our latest technology solutions, We help our customers improve their well economics.

Speaker 2

We anticipate the current natural gas prices will cause a small reduction in our rig count in the near term. However, the continued repricing of below market rates from contracts signed in previous years The current rates upon contract renewal this quarter is expected to lead to increased margins and increased overall contract drilling profitability in the As we move into the second half of the year, we anticipate that our rig count will increase driven primarily by activity in oil basins. In Pressure Pumping, the current market environment has resulted in some softness in the spot market for frac spreads. This softness contributed to increased white space in the calendar during the Q1, which combined with weather disruptions reduced utilization. But despite these challenges, I'm pleased that we were able to achieve our expectations for the Q1 revenues and margins due to the strong execution of our pressure pumping team.

Speaker 2

The pressure pumping industry continues to bifurcate as dual fuel spreads remain in higher demand due to their ability to reduce operators' fuel costs. Currently 8 of our 12 spreads are dual fuel capable. Given the current market environment, We no longer plan to reactivate our 13th spread this year. However, we will continue to convert engines to dual fuel and expect 9 of our 12 spreads to be dual fuel capable by the end of this year. In In the Directional Drilling segment, our focus continues to be distinguishing ourselves by leveraging technology, innovation and emphasizing exceptional service quality and reliability.

Speaker 2

We've established ourselves as leaders in conventionally drilling U-turn wells, which involves utilizing a high performance mud motor to drill complex wells shaped like AU enabling clients to drill 10,000 foot laterals within a single 5,000 foot section. We've even successfully drilled a well in a W shape for a customer recently. Our impact MUD motors and Empower MWD systems have demonstrated reliability contributing to the reduction in the number of trips required to replace tools and in turn boosting operator efficiency. By combining this enhanced efficiency with top notch service quality that ensures the wellbore remains within the pay zone, we can effectively improve overall well economics. As we move forward, we remain dedicated to maintaining our edge in the directional drilling industry by continually refining our technologies, fostering collaboration across our business segments and delivering reliable and efficient solutions that cater to the evolving needs of our clients.

Speaker 2

With that, I will now turn the call over to Andy Smith, who will review the financial results for the Q1.

Speaker 3

Thanks. Net income for the Q1 was $99,700,000 or $0.46 per share. Adjusted EBITDA improved to 2 $256,000,000 for the Q1 from $239,000,000 for the Q4 of 2022. In contract drilling, average adjusted rig margin per day in the U. S.

Speaker 3

Increased by $2,430 over the previous quarter of $15,880 This growth was driven by higher average rig revenue per day, which increased $2,930 due to the Successful renewal of rig contracts to current rates. Average rig operating cost per day increased $490 to $18,880 At March 31, 2023, we had term contracts for drilling rigs in the U. S. Providing for approximately $890,000,000 of future dayrate drilling revenue, up from approximately $830,000,000 at the end of the 4th quarter. Based on contracts currently in place in the U.

Speaker 3

S, we expect an average of 79 rigs operating under term contracts during the Q2 of 2023 and an average of 53 rigs operating under term contracts for the 4 quarters ending March 31, 2024. In Colombia, 1st quarter contract drilling revenues were $10,600,000 with an adjusted gross margin of $2,100,000 For the Q2, we anticipate further improvement in contract drilling profitability as the increase in margins resulting from contract renewals at current rates is expected to more than offset a slight decline in our rig count. Average adjusted rig margin per day is expected to increase approximately $1,000 while our average rig count is expected to decline 2 or 3 rigs. In Colombia, we expect to generate approximately 11 point $5,000,000 of contract drilling revenue during the Q2 with adjusted gross margin of approximately $2,400,000 In Pressure Pumping, revenues and margins were impacted by both weather disruptions and increasing white space in the calendar. Pressure Pumping revenues were $293,000,000 with an adjusted gross margin of $73,200,000 For the Q2, we expect additional white space on the calendar given the softness in the spot market.

Speaker 3

Accordingly, pressure pumping revenues are expected to be approximately $277,000,000 with an adjusted gross margin of $61,000,000 In our Directional Drilling segment, We experienced a decline in revenue and margin during the Q1 due primarily to reduced activity levels. Directional Drilling revenues were 56 $300,000 in the Q1 with an adjusted gross margin of $8,200,000 For the 2nd quarter, We expect both revenue and margin to increase by approximately $1,000,000 over the 1st quarter levels. In our other operations, which includes our Rental Technology and E and P businesses, revenues for the Q1 were $23,200,000 with an adjusted gross margin $9,100,000 For the Q2, we expect revenues and adjusted gross margin to be similar to the Q1. On a consolidated basis, in the Q1, the total depreciation, depletion, amortization and impairment expense amounted to $128,000,000 including $4,400,000 of impairment charges. For the Q2, we expect total depreciation, depletion, amortization and impairment expense of $122,000,000 Selling, general and administrative expense for the 2nd quarter is expected to be approximately $30,000,000 Interest expense for the Q1 of $8,800,000 included $1,100,000 gain from the early extinguishment of debt related to the $9,000,000 of debt we repurchased in the Q1.

Speaker 3

For the Q2, we expect interest expense to be approximately $10,000,000 Our effective tax rate for 2023 is expected to be approximately 17%, although we do not expect to pay any significant U. S. Federal cash taxes. We are lowering our 2023 CapEx forecast to $510,000,000 which equates to $480,000,000 when excluding $30,000,000 of customer funded rig upgrades. Contract drilling CapEx is expected to be approximately $290,000,000 down from our previous forecast of $320,000,000 The majority of this decrease is CapEx for maintenance and rig reactivations, which is now expected to be $180,000,000 down from $200,000,000 Included in our forecast for rig reactivation CapEx is the reactivation of 6 rigs throughout 2023, all are currently contracted.

Speaker 3

All 6 of these rig reactivations include very Additionally, approximately $30,000,000 of this year's upgrade and reactivation CapEx was paid for by the customer. Patterson UTI has a long history of being disciplined with our contracting strategy that we have no intention to reactivate any rigs without a term contract. Our pressure pumping CapEx forecast has been reduced by $20,000,000 to approximately $150,000,000 As Andy mentioned, we no longer plan to reactivate a 13 So we are upgrading a spread to Tier 4 dual fuel. With that, I'll now turn the call back to Andy Hendricks.

Speaker 2

Thanks, Andy. To summarize, we believe Patterson UTI's position as a leading provider of Tier 1 super spec rigs and our ability to leverage our technology In support of our customers' well economics through increased efficiency will result in a stable to slightly increasing rig count during 2023, despite any near term pause in market activity. Given our term contract portfolio, We expect our operating results and cash flow will improve throughout the year as we will continue to benefit from the renewal of drilling rig contracts at higher rates. Furthermore, we will continue to demonstrate Patterson UTI's long standing commitment to capital discipline through both our capital spending and our contracting strategies where we prioritize cash flow and margin over activity levels. With our substantial free cash flow, We will continue to target a return of 50% of free cash flow to shareholders through a combination of dividends and share buybacks.

Speaker 2

With that, we would like to thank all of our employees for their hard work, efforts and successes to help provide the world with oil and gas for the products that make people's lives better. Cheryl, we'd now like to open up the call to questions.

Operator

Thank you. Your first question is from Jim Rosen of Raymond James. Please go ahead. Your line is open.

Speaker 4

Hey, good morning, guys. Nice quarter. Good

Speaker 5

morning. It's amazing. Business is actually still doing well. One of the questions, Andy, is you mentioned this and obviously some of your peers have mentioned the continued kind of evolution of frac fleets to dual fuel or electric, basically tied to gas because of the huge fuel cost savings that especially is around today. And you mentioned you're adding upgrading another fleet this year, so that puts you to 9 out of 12 by end of the year.

Speaker 5

Are you seeing a discernible Kind of pricing difference for between the 2, the old Tier 2 diesel fleets versus the newer generation Tier 4 dual fuel? Or is it more just what's In customer demand that drives those decisions, I'm kind of curious, on a short term basis.

Speaker 2

Yes. So first, We continue to do the upgrades. It's been in our program now for over a year, but it really has to do with As we hour out some of the older Tier 2 engines to where it's no longer worth rebuilding, then the new engines coming in are going to be Tier 4 And so that's the starting point. And then it is economically worthwhile for us to go ahead and add The dual fuel kits on top of that because we do get a bit of a premium because the benefit for the E and Ps, of course, to be able to burn as much natural gas When they can bring natural gas to the pads. So this is an ongoing process.

Speaker 2

It's part of our maintenance CapEx. I mean it is an upgrade process, but the real upgrade is not just the Tier 4 engine that's part of the maintenance and replacing older Tier 2s, but the upgrade portion is really just adding on The dual fuel kit which is a smaller portion of the capital. So it's primarily part of the maintenance budget And we think it continues to improve the quality of our fleet. The number of spreads that are run dual fuel are going to be increasing for us And we get a bit better margin when we do that because there's a huge benefit to the E and P.

Speaker 5

Excellent. That's helpful. And then just as a follow-up, You guys have obviously posted pretty solid sequential increase in average revenue per day on, as you mentioned, contract renewals. And it sounds like that kind of move continues at least in the Q2 or through the Q2 based on guidance. 1 of your peers mentioned The strength continuing in the oily basins, but obviously they were talking about some price degradation And rigs in the gassy basins.

Speaker 5

And I'm curious just if you it doesn't seem like that's obviously impacted your fleet or your financials, but I'm curious if you've seen Others bidding that way here in recent weeks or months.

Speaker 2

Yes. I mean, I'm sure we're going to get a few questions On what day rates are doing and pricing, it's really about what we choose to do in the market. And Our choice is that we don't see a need to reduce the rates on the rigs. We think that we've got high quality rigs that can work. We see any kind of slowdown in activity as just a pause, especially in the natural gas basin, given the demand that's going to occur for LNG and feeding LNG Trains and Systems.

Speaker 2

And so we just don't see the need to reduce the rates. We still see demand in the oil basins. And so with any slowdown in the natural gas basins, we'll just wait and work those rigs when that activity starts to pick up again.

Speaker 5

Makes perfect sense. Thanks.

Operator

Your next question is from Saurabh Pant of Bank of America. Please go ahead. Your line is open.

Speaker 6

Hi, good morning. Good morning, Andy and Andy.

Speaker 2

Good morning, Saurabh.

Speaker 6

I guess I'll just follow-up on the rig side first and then maybe one on the pressure pumping side. I mean, I guess it's unfair to ask you to comment on others, right? But I can't help but ask because it's such a contrasting outlook for the Q2. A couple of your peers, big ones reported earlier And they're talking about a 9% to 10% decline in their activity 1Q to 2Q. And on your numbers, it sounds like your activity is expected to be down just 2%.

Speaker 6

Why do you think you're doing so much better? Is it about your base in our customer mix? Is it just about the way the rigs roll off contract? Is there something else? Because the data seems just too much for what we have historically seen.

Speaker 6

So just want to clarify that, please, Andy.

Speaker 2

Yes, I think let's start that discussion by looking at what's going on in the different basins. I mean, we are seeing changes happening in different basins. In Bakken oil, we've seen some slowdown in Mid Con. Mid Con, you're producing for both oil and gas And rigs drilling for gas have seen some slowdown in the Mid Con. South Texas, you've got a mix of rigs drilling for some oil, some gas.

Speaker 2

And then of course you got Haynesville covering East Texas and Louisiana. And so I think those are basins that of course we operate in, But we're more heavily weighted and this is a positive for us to the Permian and also to the Northeast. Now the Northeast is a gas basin, But we anticipate that our activity stays relatively steady up there. That's a gas basin that's as all of you all well know is A bit segregated from the rest of the pipeline structure in the U. S.

Speaker 2

And that services the Northeast Industrial and Heating market. And so We see stability in the Northeast. We see long term growth in the Permian. And I think you're seeing some near term challenges in Mid Con South Texas along with the Haynesville. And while we operate there, we have less waiting in those basins.

Speaker 2

So I think It's just the basin waiting for different drilling contractors on how things are being affected right now.

Speaker 6

Okay, okay. No, that makes sense. And then just quickly on the pumping side, I think you talked about white spacing going up. Obviously, spot market looks like it's a little loser than it was 3 or 6 months back. In general, Andy, just help me think about how do you think about the Decision point on whether you're willing to accept that extra white spacing taking Let's say near term hit to profitability, right?

Speaker 6

But like you said, this might be a pause and things might start to get better. How do you think about this taking a short term hit on profitability due to white space versus just saying I'm going to stack 1 of my 12 fleets that are working on there?

Speaker 2

Yes. So it's trying to fill the calendar out, it's a little more complex. We can't just stack a spread and then continue to support The customers, we are going to have to work through some white space and that's going to bring down margins a little bit, but it's I think when you look at the pressure pumping market in the places that we're operating, which are primarily the Delaware Basin, where you've got higher pressure, higher rates And in the Northeast where we do a lot of the Utica higher pressure, higher rates, in those markets, we're seeing pricing holding steady. And it's really the white space that's affecting us, but we've got customers that are pulling back on their schedules and we're just going to have to adjust with that for now. But again, I see it more as a pause.

Speaker 2

And I think later in the year, this activity will fill out the calendar and we'll see less white space later in the year.

Speaker 6

Okay, okay, okay. Perfect, Andy. Thanks for those answers. I'll turn it back.

Operator

Your next question is from Kurt Hallead of Benchmark. Please go ahead. Your line is open.

Speaker 4

Hey, good morning. Good morning. Yes, quite a radical differential relative to some of your other peers. So, Just to some of your other peers, so excellent execution, Andy. Congrats to everybody there.

Speaker 4

Hey, just kind of curious, right, as you referenced The dynamics first on the drilling front with your exposure more to the Marcellus than maybe to the Angel and some other areas. So understanding the structural differences of that market, but also understanding that your Customer base will take every opportunity to kind of chip away and get better terms and better pricing. Would you give us some insights as to the discussions you've been having lately? And has the typical friction around discussions Trends on pricing, is that have you seen any change in that whatsoever? Have the E and Ps got a little bit more aggressive than they have been in recent quarters?

Speaker 2

Kurt, it's certainly the E and Ps have to do their job and they have to ask. But I wouldn't say things have necessarily gotten more aggressive, Especially in some of the more challenged gas markets like the Haynesville, which have been more affected by gas prices coming Either it makes sense to drill a well or it doesn't. And so us reducing the day rate on a rig by 10% or 15% is not going to boost the economics to get a well drilled. So, I wouldn't say we're seeing a lot of pressure. I would it's really more The challenges in some of the basins that I was mentioning earlier around Mid Con, South Texas and the Haynesville and where you've got gas production, Where we're just seeing some slowdowns, we're going to have some rigs come down in those basins, but we're also at the same time Because of our reactivations putting rigs into the Permian and oil basins, so we've got some moving pieces in our rig count.

Speaker 2

But for us, The net is we're only going to be down a few rigs, but it's really kind of where we're positioned in the basins today. But in terms of aggressiveness, I wouldn't say that we're seeing it so much, but again, like I was saying earlier, it's about our choice. We choose not to work at the lower rates. And you're probably going to hear some anecdotal evidence of some drilling contractors that are lowering some rates. But We think very highly of our teams and of our rigs and our pressure pumping equipment and we just don't feel the need to do that.

Speaker 4

Okay. That's good color. So a follow-up on the frac side. So you obviously spelled it out, you're going to have 9 exiting this year, 9 of your 12 frac fleets will be Dual fuel. So I was just kind of curious as the market is evolving here and clearly moving toward the dual fuel for obvious Cost reduction and efficiency gains and etcetera, what's your take on electric frac And maybe longer term, Andy, how would you see the mix of your assets?

Speaker 2

Yes, I'll lump electric into various new technologies that employ natural gas as the primary fuel. And I think that there is there are some interesting technologies out there. It's not just electric. We're experimenting with a few and we've seen some really good results. We've got some customers that are really happy with our ability to boost their ability to use natural gas at the well site and improve their economics.

Speaker 2

And we'll keep you posted on what we're doing later, but I don't see us buying, for instance, A new electric spread, unless we were to get a term contract that really fully supported that investment and had a good return on that. I don't think that's going to happen in this environment. We just haven't seen it. But I think we have some other things that we can do with some new technology to improve the use of natural gas.

Speaker 4

Okay, great. Really appreciate the color. Thanks.

Operator

Your next question is from Derek Podaser of Barclays. Please go ahead. Your line is open.

Speaker 4

Hey, good morning, guys. I just wanted to go back to

Speaker 7

the comment around Seems like your rig count is a little bit more defensive than one of your larger peers. Obviously, they're dropping more than double than the rigs you are. I know you went through it a little bit, but can you also hit on, Is this also a function of your term versus spot contract? And then also your customer mix? Just maybe a little more color On those two dynamics to help us understand the differences between you and your peers.

Speaker 2

Yes. Derek, good morning. It's Tough for me to really say what our term versus spot is relative to our peers because I really don't know what they have. I would say we have good term coverage, But I would take it back more to the basins and then some of the customers that we have in these basins. Our weighting is more towards the Permian and The Northeast on the drilling rigs and even on the pressure pumping.

Speaker 2

And so we're seeing Steady work up in the Northeast in that gas basin and over time I think we're going to see increasing activity in the Permian, Especially depending on where oil goes. If oil goes back over $80 then yes, 100%, you're going to see the rig count and spread count Increase in the Permian and consume all available equipment on the market. So it's really more about the basins, I think.

Speaker 7

Got it. Thanks for that. You talked about the second half, you're expecting the rig count to increase here, so maybe bottom out over the summer months and then Just can you unpack what gives you the confidence to talk about a rig increase in the back half of the year? Are you talking to your customers? Do you have rigs locked up Come on to work, just maybe a little bit of help around what gives you the confidence to see rigs going up in the back half?

Speaker 2

It's really around discussions with customers and even if what we're doing in the natural gas basin stays relatively flat, I think that throughout the year you're going to see the potential to increase in the oil basins. And so that's going to drive a lot of that now. Of course, where the commodity is, is going to drive the rate of increase and we'll see how that plays out over the next few months. But on the natural gas side, in discussions with some of the customers, we do have customers that anticipate that they're going to need to get well inventory in the ground For the upcoming demand on LNG and that's going to happen towards the end of this year and into 2024. So we do see this natural gas reduction in activity as a pause more than anything else.

Speaker 4

Great. Appreciate the color. I'll turn it back.

Operator

Your next question is from John Daniel of Daniel Energy Partners. Please go ahead. Your line is open.

Speaker 8

Hey, guys. Thanks for including me. I got three questions today. First, just on to the last one you just answered, Andy, Assuming the rig count does recover later this year based on those discussions, are you already having discussions with those Customers about the price of the rigs?

Speaker 2

So for us, this is a pretty short discussion on the price of the rig. I mean, the price is what it is. We think that where the rig rates have moved over the last years where they need to be and really pleased with how We continue to be able to reprice older contracts from last year at current rates this year, which is going to Improve our margins quarter on quarter this year. So for us with the type of rigs we operate and the performance track record Of our teams and the technologies that are employing on the rigs, the day rate is the day rate.

Speaker 4

Fair enough.

Speaker 8

To your credit, the larger players have been, as you know, more vocal about defending price. I'm curious if when you go, let's say, we're 6 months from now and we're looking at the overall rig count change, Are we going to see a scenario where maybe the larger public players have lost a bit more share just because some E and Ps, Right or wrong, ought to use a lower price rig from smaller competitors. So in other words, is the overall rig count decline a little bit less than maybe what some of the guidance is from The top four guys, if that makes any sense.

Speaker 2

It's hard for us to look at the overall rig count these days Given our coverage with customers and we don't provide SCR mechanical rigs, We've seen those come down fast. We've seen those come down.

Speaker 6

We saw

Speaker 2

a lot of those rigs being used by Private Equity backed E and Ps that were trying to prove up acreage and they're trying to manage their P and Ls and their valuation. So I could See those rigs coming back and potentially taking share away from the larger drilling contractors, the public drilling contractors that are using Super spec rigs, but it is what it is. It doesn't affect us.

Speaker 8

Okay. Last one was more of an operational question. Matador called out the U shaped lateral in their earnings and you obviously referenced it too. I'm assuming maybe you're working for them.

Speaker 6

I'm curious assuming you're doing the frac, how does

Speaker 8

that impact the utilization for the Assuming you're doing the frac, how does that impact the utilization for the spread? What are the benefits to it? And how broad based is this trend? Yes.

Speaker 2

For the jobs that I know of that we're doing the hydraulic fracturing on the U shaped wells, I'm not aware Any difference on how we operate those versus just a straight lateral. And we've done the U shape for a few different E and Ps. Certainly, the public data out there that shows that we work for Matador and really Please to have them as a customer and pleased to be able to trial some of these new technologies with them.

Speaker 8

Fair enough. I guess I'll just dumb it down, so I can understand it. If you were doing 25,000 foot laterals And just to make up the number, it took 4 days for each of those 2, 5000 foot laterals to complete. Is it now 7 by doing the U? I'm just trying to see if there's a how much if there's a savings in job time?

Speaker 2

It's really because you're drilling in a You're working in a single section and you're trying to maximize your exposure to reservoir in that section. So it's 25,000 foot laterals plus You've got the turn on the U where you've exposed reservoir there and some operators will frac that section of the U As well where we do the turn, but it's not necessarily that you're doing that to improve efficiencies, it's because you're constrained by lease lines In a 5,000 foot square section.

Speaker 8

Okay, fair. Well, thank you for including me.

Speaker 2

Yes. Thanks, John.

Operator

Your next question is from Don Crist of Johnson Rice. Please go ahead. Your line is open.

Speaker 9

Good morning, gentlemen. Thanks for letting me in. Just one Quick question on broader based anyway. Are you planning to stack rigs in basin Just because you think that this is a pause, if there's any weakness in the basin that you're operating in? And kind of following on to that, are you seeing your competitors Try to move rigs around to the higher activity basins today, I.

Speaker 9

E, do you think rigs could move a large amount of rigs can move In the Permian per se and kind of affect spot pricing there?

Speaker 2

Yes, good morning. So to begin with, we have Stacked natural gas rigs in natural gas basin. We had that's already in the public data that we've had some rigs come down in the Haynesville And we've just chosen to stack it there. And we think that this is a pause in time that that rig will go back to work. We're able to use the crews In other areas to help fill in on work, so that's not a problem there.

Speaker 2

Do I think that rigs will move? Rigs will move When E and Ps pay for the mo. And so there may be cases where rigs move from some base to other, But the mobilizations are paid for by the E and Ps when we do that. We've had at least one case where we've had an E and P pay to move a rig From a South Texas, South Central Texas basin over to the Permian. So it does happen.

Speaker 2

I wouldn't say that it's going to be in a large number right away. And I would say that if there are some drilling contractors that get aggressive on price, It's they're in a different situation. So getting into some of more of those details, if you're a large drilling contractor, there's no reason For you to reduce your rates, that doesn't benefit you. I mean that's we're all trying to do the right thing for our shareholders at the end of the day. If you're a small drilling contractor and you're losing a few rigs, that's material and it's meaningful and you may do what you can to keep those rigs working.

Speaker 2

We don't have to choose those rates and we choose not to take those rates.

Speaker 9

Okay. And if I could sneak in one other one, obviously the Are you seeing any movement on steel or labor or any other kind of cost input, Given that there's more people available, etcetera?

Speaker 2

So labor is what it is. It's still relatively tight. We are seeing where I'm hearing from operators that they're getting breaks on tubulars in terms of casing. In terms of drill pipe, we still buy a lot of high end, high torque double shoulder connection drill pipe from a large public supplier who does a great job for us and we're not seeing any breaks on that pipe that's still very high in specialty pipe that has a long lead time. But on the completion side, we're seeing that we can get sand at better rates and we're passing on those savings to E and Ps where we can.

Speaker 2

And so overall, there are some cost savings that E and Ps are getting. It's going to be around their casing. It's going to be around sand in some cases, but I don't see big changes in the service rates.

Speaker 9

Okay. I appreciate the color. Thank you, Andy.

Speaker 2

Thanks.

Operator

Your next question is from Keith MacKay of RBC Capital Markets. Please go ahead. Your line is open.

Speaker 10

Just wanted to start out in frac. Appreciate the dynamic in the spot market. Can you just talk a little bit about your Spot market exposure relative to the contracted portion of your fleet and how might you expect that to change throughout the year?

Speaker 2

Yes, we have about a quarter of what we do that has some spot market exposure and that's we're seeing some white space in the calendar. I don't expect any real change throughout the year there. When I say spot, that could still be for a period of time, not just 2 wells, 3 wells at a time. So there is some continuity even in that spot market, but we just are seeing a little bit more white space. But it's not again affecting service pricing per se.

Speaker 2

It's really just affecting margins because of the way things are falling in the calendar.

Speaker 10

Got it. Thanks for that. And so no additional spread activation this year, but the dual fuel conversion, Does that rule out then an additional activation for next year? Like are the engines that you've got being used To swap out existing equipment and now there's that kind of precludes you from putting together an additional fleet next year. And And can you just kind of help us, if that's the case, think about what CapEx and Pressure Pumping should be next year relative to the $150,000,000 this year?

Speaker 2

So the upgrade to the Tier 4 again is part of our maintenance budget. So that's coming out of the maintenance CapEx. And The addition of the dual fuel systems, I consider that more an upgrade where we're going to try to get better rates for that. And I think the market still supports that. Again, no plans to reactivate, but that's really based on looking at current market conditions.

Speaker 2

Now if oil moves over $80 and it stays there for a fair period of time, that could change the dynamics going into 2024 And we can see some demand from existing customers today. So I think we just have to wait and see how this year plays out. I think a lot of it will be driven by What the commodities do throughout this year.

Speaker 4

Understood. Thanks very much. Thanks.

Operator

Your next question is from Kurt Hallead of Benchmark. Please go ahead. Your line is open.

Speaker 4

Hey, I got a quick follow-up coming back around to the other Andy's financial guidance. So if I do my math correctly, Looks like gross profit and operating income should be roughly flat with Q1. Am I looking at it the right way?

Speaker 3

On a consolidated basis?

Speaker 4

Yes.

Speaker 3

Yes. Hang on one second. I think that's about right, but let me pull something up here real quick. Yes, that's right.

Speaker 4

Awesome. All right. Appreciate that. That's it for me. Thanks.

Operator

There are no further questions at this time. I will now turn the call over to we actually have one more question. John Daniel of Daniel Energy Partners, your line is open.

Speaker 8

I couldn't wait an opportunity. I'm just so excited to talk, Angeline. Real quick, when the market does recover, can you just speak to the timing and the cost of bringing the rigs back out? I mean, I would assume not much, but just any thoughts.

Speaker 3

When the market recovers, the timing and

Speaker 2

costs The timing and costs to bring rigs back out.

Speaker 8

Yes.

Speaker 2

So timing relatively short, cost relatively low. We don't necessarily consider that A reactivation that we had to budget growth CapEx for because if a rig is only down for a few months, We don't have to do much to it. So not the same economics as if we're reactivating a rig that's been down for 2 years. And that's in our CapEx budget, we've got reactivations in there where it was around $2,000,000 to bring back a rig that's It's been down for a couple of years and then some of those rigs have upgrades on top of that. And so we considered that growth CapEx, but I don't This will probably just fall into maintenance CapEx to bring a rig back out that's only been down for a few months.

Speaker 8

Great. Thank you very much.

Speaker 4

Thanks. Thanks, John.

Operator

I will now turn the call over to Andrew Hendricks for closing remarks.

Speaker 2

Well, I'd like to thank everybody who Joined us on the call this morning and appreciate all the questions. And again, thanks to our team at Patterson UTI for the great job that everybody is doing. Thanks. Thanks.

Operator

This concludes today's conference call. Thank you for your participation. You may now disconnect.

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