Q1 2023 Patterson-UTI Energy Inc. Earnings Call
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. If you would like to ask a question. During this time simply press star followed by the number one on your telephone keypad. If you would like to withdraw your question again press Star one.
Thank you, Mike <unk>, Vice President Investor Relations you May begin your conference.
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 three 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 fleece expectations or predictions for the future are forward looking statements. 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.
On 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 pet energy Dot com and in the company's press release issued prior to this conference call.
Now, it's my pleasure to turn the call over to Andy Hendricks sports from opening remarks, Andy.
Thanks, Mike Good morning, and thank you for joining us today for Patterson Utis first quarter conference call.
We are pleased to report another quarter of solid financial results.
The exceptional results in our contract drilling segment and demonstrate our ongoing ability to capitalize on the robust demand for tier one super spec rigs and the renewal of drilling rig contracts at current rates.
During the first quarter, we continued to return capital to shareholders and strengthen our balance sheet at the same time, we repurchased five 6 million shares of our common stock for $73 $6 million, and we repurchased $9 million of long term indebtedness for only $7 8 million.
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 has led to what we believe to be a transitory in mid cycle pause in activity.
However, we expect relative stability in the rig count for tier one 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 first quarter 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.
This high grading, which positively impacts well economics has supported demand across the industry for tier one 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 one super spec rigs and we will 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 one super spec rigs and integrating our latest technology solutions, we help our customers improve their well economics.
We anticipate the current natural gas prices will cause a small reduction in our rig count in the near term.
However, the continued re pricing of below market rates from contracts signed in previous years to current rates upon contract renewal. This quarter is expected to lead to increased margins and increased overall contract drilling profitability in the second quarter.
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 in 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 first quarter, which combined with weather disruptions reduced utilization.
But despite these challenges I'm pleased that we were able to achieve our expectations for the first quarter revenues and margins due to the strong execution of our pressure pumping team.
The pressure pumping industry continues to bifurcate is dual fuel spreads remain in higher demand due to their ability to reduce operators fuel costs.
Currently eight 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 nine of our 12 spreads to be dual fuel capable by the end of this year.
In the directional drilling segment, our focus continues to be distinguishing ourselves by leveraging technology innovation and emphasizing exceptional service quality and reliability.
We've established ourselves as leaders in conventionally drilling you turn wells, which involves utilizing a high performance mud motors to drill complex wells shape like au, enabling clients to drill 10000 foot laterals within a single 5000 foot section.
We've even successfully drilled a well in a W shape for a customer recently.
Our impact mud motors and empower MW DC systems have demonstrated outstanding 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 continuously refining our technologies fostering collaboration across our business segments, and delivering reliable and efficient solutions that cater to the evolving needs of our clients.
With that I will now turn the call over Andy Smith, who will review the financial results for the first quarter.
Thanks.
Net income for the first quarter was $99 $7 million or <unk> 46 per share.
Adjusted EBITDA improved to $256 million for the first quarter from $239 million for the fourth quarter of 2022.
In contract drilling average adjusted rig margin per day in the U S increased by 2000 and $430 over the previous quarter to $15880.
This growth was driven by higher average rig revenue per day, which increased to $930 due to the successful renewal of rig contracts to current rates.
Average rig operating cost per day increased $490 to $18880.
At March 31, 2023, we had term contracts for drilling rigs in the U S providing for approximately $890 million of future day rate drilling revenue up from approximately $830 million at the end of the fourth quarter.
Based on contracts currently in place in the U S. We expect an average of 79 rigs operating under term contracts during the second quarter of 2023, and an average of 53 rigs operating under term contracts for the four quarters ending March 31 2024.
In Colombia first quarter contract drilling revenues were $10 $6 million with an adjusted gross margin of $2 $1 million.
For the second quarter, 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, while our average rig count is expected to decline two or three rigs.
In Colombia, we expect to generate approximately $11 $5 million of contract drilling revenue during the second quarter with adjusted gross margin of approximately $2 4 million.
In pressure pumping revenues and margins were impacted by both weather disruptions and increasing white space on the calendar.
Pressure pumping revenues were $293 million with an adjusted gross margin of $73 2 million for.
For the second quarter, we expect additional white space on the calendar given the softness in the spot market.
Accordingly pressure pumping revenues are expected to be approximately $277 million with an adjusted gross margin of $61 million.
And our directional drilling segment, we experienced a decline in revenue and margin during the first quarter due primarily to reduced activity levels.
Directional drilling revenues were $56 $3 million in the first quarter with an adjusted gross margin of $8 $2 million.
For the second quarter we.
We expect both revenue and margin to increase by approximately $1 million over the first quarter levels.
In our other operations, which includes our rental technology and E&P businesses revenues for the first quarter were $23 $2 million with an adjusted gross margin of $9 1 million.
For the second quarter, we expect revenues and adjusted gross margin to be similar to the first quarter.
On a consolidated basis in the first quarter, the total depreciation depletion amortization and impairment expense amounted to 128 million, including $4 $4 million of impairment charges for.
For the second quarter, we expect total depreciation depletion amortization and impairment expense of $122 million.
Selling general and administrative expense for the second quarter is expected to be approximately $30 million in.
Interest expense for the first quarter of $8 8 million included $1 $1 million gain from the early extinguishment of debt related to the $9 million of debt, we repurchased in the first quarter.
For the second quarter, we expect interest expense to be approximately $10 million.
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 million, which equates to $480 million when excluding $30 million of customer funded rig upgrades.
Contract drilling Capex is expected to be approximately $290 million down from our previous forecast of $320 million.
The majority of this decrease is capex for maintenance and rig reactivation, which is now expected to be $180 million down from $200 million.
Included into our forecast for rig reactivation capex.
As the reactivation of six rigs throughout 2023, all are currently contracted.
All six of these rig reactivation include various specific packages requested by the customers, including emission reducing upgrades such as natural gas engines for utility skits for island power <unk>.
Additionally, approximately $30 million 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 million to approximately $150 million as Andy mentioned, we no longer plan to reactivate a 13th spread but we are upgrading our spread to tier four dual fuel.
With that I'll now turn the call back to Andy Hendricks.
Thanks, Andy.
To summarize we believe Patterson uti's position as a leading provider of tier one super spec rigs and our ability to leverage our technology and 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 has 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 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.
With that we'd 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 wed now like to open up the call to questions.
Thank you to ask a question please press star one.
First question is from Jim Rollyson of Raymond James. Please go ahead. Your line is open.
Hey, good morning, guys nice quarter, Jim Good morning.
It's amazing business is actually still doing well.
One of the questions. Andy is you mentioned that and obviously some of your peers have mentioned the continued kind of evolution.
Frac fleets to dual fuel or electric basically tied to gas.
The huge fuel cost savings, especially is around today.
And you mentioned youre, adding and upgrading another fleet. This year. So let's put you to nine out of 12 antibody end of the year are you seeing a discernible kind of pricing difference between the two the old tier two diesel fleets versus the newer generation tier four dual fuel or is it more just what's in customer demand.
<unk>.
That drives those decisions I'm kind of curious on the short term basis.
Yes. So first we continued to do the upgrades its been in our programme now for over a year.
But it really has to do with as we our out some of the older tier two engines to where it's no longer worth rebuilding than the new engines coming in are going to be tier four in.
And so that's 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 it's a benefit for the e&ps of course build the burn as much natural gas as they can when they can bring natural gas to the pad.
This is an ongoing process, it's part of our maintenance Capex.
I mean, it is an upgrade process, but the real upgrades not just the tier four engine thats part of the maintenance and replacing older tier twos, 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.
Quality of our fleet the number of spreads that are run dual fuel are going to be increasing for us and we get better margin. When we do that because there is a huge benefit to the E&P.
Excellent that's helpful and then just as a follow up.
You guys are obviously, you posted pretty solid sequential increase in average revenue per day.
We had some contract renewals and it sounds like that that kind of move continues at least in the second quarter through the second quarter based on guidance one 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 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 getting that way here in recent weeks or months.
Yes, I'm sure we're going to get a few questions on what day rates are doing in pricing, it's really about what we choose to do in the market and our choices that we don't see a need to reduce the rates on the rigs.
That we've got high quality rigs that can work, we see any kind of slowdown in activity is just a pause, especially in the natural gas basins, given the demand that can occur for LNG and feeding LNG trains and systems 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 will just wait and work those rigs when that activity starts to pick up again.
It makes perfect sense. Thanks.
Your next question is from Rob <unk> of Bank of America. Please go ahead. Your line is open.
Hi, Good morning, Good morning, Andy and Andy Good morning, Rob.
I guess I just follow up on the rig side and then maybe one on the pressure pumping side.
Yes, it's unfair to ask you to comment on others.
Got it got it held back because it's got the contracting outlook for the second quarter a couple of your peers.
Big one we reported.
And they are talking about a 9% to 10% decline in that activity <unk>.
A number of it sounds like YOD activity is expected to be down just 2%.
Why do you think you are doing so much better is it about basing our customer mix is just about the way the rigs roll off contract that that is something guys.
<unk> I think there's just too much for.
But what we haven't got it can be seen so just wanted to clarify that.
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, and 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 has seen some slowdown in the mid Con South, Texas, you've got a mix of rigs drilling for some oil <unk> gas and then of course, you've got haynesville covering.
East, Texas, and Louisiana and so.
Those are basins that of course, we operate in but we are more heavily weighted and this is a positive for us to the Permian and also to the northeast and 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 all.
All of you all well know us.
Segregated from the rest of the pipeline structure in the U S net services, the northeast industrial and heating market.
So we see stability in the northeast, we see long term growth in the Permian and I think youre seeing some near term challenges and mid Con South, Texas, along with the Haynesville and.
While we operate there we have less waiting in those basins. So I think it's it's.
It's just the basin waiting for different drilling contractors on how things are being affected right now.
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 its a little looser than it was.
Six months back engender.
When you think about how do you think about that decision point.
Whether you are willing to accept that external white spacing.
Taking a look.
Near term hit to profitability rate, but like you said it might be a pause and things might start to get better how do we think about just taking a short term hit on profitability due to white space.
I think I'm going to stack one off microphone fleets that are working on there.
Yes, so it's trying to fill the calendar adds a little more complex, we can't just stack a frac stack a spread and then continue to support the customers.
We are going to have to work through some white space and thats going to bring down margins a little bit.
I think when you look at the pressure pumping market.
In the places that we are 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 and I think later in the year. This activity will fill out the calendar and we will see less white space later in the year.
Okay. Okay. Okay, both Andy Thanks for those answers I'd turn it back.
Your next question is from Craig Hallum.
Benchmark. Please go ahead your line is open.
Hey, good morning.
Yes, quite a quite a quite a radical differential relative to some of your other peers. So excellent execution, Andy congrats to everybody there.
Hey, just kind of curious right as you referenced the dynamics first on the envelope on the drilling front with your exposure more to the Marcellus and maybe to the Haynesville and some other areas.
So.
Understanding the structural difference is of that market, but also understanding that your customer base will take every opportunity to kind of chip away.
And get better.
Better terms and better pricing.
Would you.
Give us some insight as to the discussions you've been having lately and has the typical friction around discussions on pricing is that have you seen any change in that whatsoever had had the A&P has got a little bit more aggressive than than they had been in recent quarters.
Kurt.
Certainly the e&ps have to do their job and they have to ask but.
But I wouldn't say things are necessarily gotten more aggressive.
Especially in some of the more challenged gas markets like the Haynesville, which had been more affected by gas prices coming down 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.
It's really more of the challenges in some of the basins that I was mentioning earlier around mid Con South, Texas, and the Haynesville, 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 reactivation is putting rigs into the Permian in the oil basins. So we've got some moving pieces in our rig count but for us the net.
Ed is we're only going to be down a few rigs.
But it's really kind of where we are 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 in each of our rigs in.
Our pressure pumping equipment, and we just don't feel the need to do that.
Okay. That's good color so on follow up on the Frac side.
Obviously, you spell it out youre going to have nine exiting this year nine of your 12, Frac fleets will be dual fuel.
So I'm just kind of curious as the market's evolving here and clearly moving toward the dual fuel for obvious.
Cost reduction and efficiency gains et cetera.
What's your take on electric Frac fleets, and maybe longer term, Andy how would you see.
The mix of your assets.
Yes ill 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.
Our experiment with a few and we've seen some really good results. We've got some customers are really happy with our ability to boost their ability to use natural gas as a well site and improve their economics.
And we will keep you posted on what we're doing later, but.
I don't see us buying for instance.
New electric spread unless we were to get a term contract. It really fully supported that investment and had a good return on that and I don't think thats going to happen in this environment and 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.
Okay, Great really appreciate the color. Thanks.
Your next question is from Derek <unk> of Barclays. Please go ahead. Your line is open.
Hey, good morning, guys I just wanted to go back to the comment around it seems like Youre recap a little bit more defensive than one of your larger peers. Obviously they are dropping.
More than double than the rig 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.
Yes Derrick.
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.
So we're seeing steady work up in the northeast and that gas basin and over.
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 yet 100% youre going to see the rig count and spread counts increase in the Permian and consume all available equipment on the market.
It's really more about the basins I think.
Got it.
Thanks for that.
You talked about the second half youre expecting the rig count to increase here, so maybe bottomed out over the summer months in that increase.
Just can you unpack what gives you the confidence to talk about our rig increase in the back half of the year are you talking to your customers do you have rigs locked out to come on to work just maybe a little a little bit of help around what gives you the confidence to see rates going up in the back half.
It's really 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 youre going to see the potential to increase in the oil basins and so thats going to drive a lot.
A lot of that now of course, where the commodity 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.
Great appreciate the color I'll turn it back.
Again to ask a question. Please press Star one. Your next question is from John Daniel Daniel Energy Partners. Please go ahead. Your line is open.
Hey, guys. Thanks for taking any.
I've got three questions today first just on to that 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.
So for US this is a pretty short discussion on the price of the rig I mean, the prices where it is we think that where the 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 employed on the rigs.
The day rate as the day rate.
Okay fair enough.
To your credit the larger players have been.
As you know more vocal about defending price I'm.
I'm curious.
Let's say six months or now we're looking at the overall rig count.
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&ps.
Right or wrong opt 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 that makes any sense.
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 SaaS, we've seen those come down.
We saw a lot of those rigs being used by private equity back.
E&ps that we're trying to prove up acreage.
And they're trying to manage their P&L 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.
Okay.
Last one was more of an operational question.
Matador had called out a U shaped lateral and their earnings.
And you obviously referenced it to I'm, assuming maybe youre looking for them.
Curious, assuming youre doing the frac, how does that impact the utilization or the spread what are the benefits to it.
And how broad based is this trend.
Yes.
For the jobs that I know of that we're doing the hydraulic fracturing on the U shape wells I'm not aware of any.
Any difference on how we operate those versus just straight lateral.
And we've done that U shape for a few different e&ps.
Certainly the public data out there that shows that we worked for Matador and really pleased to have them as a customer.
Im pleased to be able to trial some of these new technologies will.
Fair enough I guess I'll just dumb it down so I can understand if you were doing two 5000 foot laterals and it's just makeup a number to four days for each of those two 5000 foot laterals to complete seven by during the year.
Trying to see if there's how much interest savings.
John .
It's really because you're drilling in <unk>.
Looking at a single section and you are trying to maximize our exposure to the reservoir in that section.
So.
It's two 5000 foot laterals plus you've got the <unk>.
Turn on the you were you would expose 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 youre doing that to improve efficiencies, it's because you're constrained by lease lines and a 5000 foot square section.
Okay. Okay.
Thank you for including me.
Yeah. Thanks, John .
Your next question is from Don Crist of Johnson Rice. Please go ahead. Your line is open.
Good morning, gentlemen, thanks for letting me in just one quick question on broader based anyway.
Planning to stack rigs in basin, just because you think that this is a pause if theres 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 E. Do you think.
Rigs could move a large amount of rigs can move in.
In the Permian per se and kind of FX spot pricing there.
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 button.
Time that that rig will go back to work, we're able to use the cruise and other areas to help fill in on work. So that's not a problem there.
Do I think that rigs will move rigs will move when e&ps pay for the mobe and so there may be cases, where rigs moved from Sunday to other but.
The mobilizations are paid for by the E&ps when we do that we've had at least one case, where we've had an E&P pay to move a rig.
From a south, Texas, South Central Texas basin over to the Permian.
So it does happen 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 to get aggressive on price.
<unk>.
There are different situations so.
Getting into some of more of those details if youre a large drilling contractors. There's no reason for you to reduce your rates that doesn't benefit 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 youre, losing a few rigs that's material and its meaningful and you may do what you can to keep those rigs working.
We don't have to choose those rates and we choose not to take those rates.
Okay, and if I could sneak in one other one obviously the rig count is coming down a little bit are you seeing any movement on steel or labor or any other kind of cost input.
Even if theres more people available et cetera.
So labor is what it is it's still relatively tight.
We are seeing where I'm hearing from operators that they are getting breaks on tubular in terms of casing.
In terms of drill pipe, we still buy a lot of high end high torque double shoulder connection drill pipe.
<unk>.
Public supplier, who does a great job for us and we're not seeing any breaks on that pipe thats still very high end specialty product. It is 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&ps, where we can.
So overall there are some some.
Cost savings the E&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.
Okay I appreciate the color. Thank you Andy.
Again to ask a question. Please press star one. Your next question is from Keith Mackey of RBC capital markets. Please go ahead. Your line is open.
Hey, good morning, and thanks for taking my questions just wanted to start out and 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.
How might you expect that to change throughout the year.
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 two wells three 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, it's really just affecting margins because of the way things are falling in the calendar.
Got it thanks for that and so no no additional spread activation this year, but the dual fuel conversion.
Does does that rule out than on <unk>.
Additional activation for next year like are the engines that you've got being used.
To swap out existing equipment and now there is.
That kind of precludes you from putting together an additional fleet next year and can you just kind of help us.
If that's the case think about what capex in pressure pumping should be next year relative to the 150 this year.
So the upgrade to the tier four again as part of our maintenance.
So that's coming out of the maintenance Capex and then the addition of the dual fuel systems I consider that more of 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 thats really based on looking at current market conditions 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 could see some demand from existing customers. Today. So I think we just have.
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.
Understood Thanks very much.
Yes.
Your next question is from Kurt Habib of benchmark. Please go ahead. Your line is open.
Hey, I got a quick quick follow up Scott coming back around to.
The other Amd's financial guidance, so if I do my math correctly it look.
Like gross profit and operating income should be roughly flat with first quarter.
Am I looking at it the right way.
Okay.
Yes.
On a consolidated basis, yes, yes.
Hang on one second.
I think that's about right, but let me.
Pull something up here real quick.
Yes, that's right.
Alright, I appreciate that that's it for me thanks.
Yeah.
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.
Thank you.
Yeah.
I'm just so excited to talk about.
Got it.
Real quick when the market does recover.
Can you just speak to that.
Timing and the cost of bringing the rigs back out.
Well I mean, I would assume not much but just any thoughts.
When the market recovers.
Timing and the cost to bring rigs back out.
Yeah. So.
Timing relatively short cost relatively low we don't necessarily consider that.
Our reactivation that we've had to budget growth cap capex for because if a rig is only down for a few months, we don't have to do much to it so okay not the same economics.
If we're reactivating a rig that's been down for two years.
<unk>.
That's.
And our Capex budget, we've got reactivation in there where it was around $2 million to bring back a rig that's been down for a couple of years and then some of those rigs of upgrades on top of that and so we consider 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.
Great. Thank you very much.
Thanks, Sean.
I will now turn the call over to Andriy Hendrix for closing remarks.
Well I'd like to thank everybody, who joined us on the call. This morning, and I appreciate all the questions.
Again, thanks to our team at Patterson UTI for the great job that everybody's doing thanks.
Thanks.
This concludes today's conference call. Thank you for your participation.