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 speaker's 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 Drickamer, Vice President, Investor Relations, you may begin your conference. Thank you, Cheryl. Good morning. On behalf of Patterson-UTI Energy, I'd like to welcome you to today's conference call to discuss results for the three months ended March 31st, 2023. Participating in today's call will be Andy Hendricks, Chief Executive Officer, and Andy Smith, Chief Financial Officer. A quick reminder as 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. 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, patenergy.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 for some opening remarks. Andy? Thanks, Mike. Good morning, thank you for joining us today for Patterson-UTI's first 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 first quarter, we continued to return capital to shareholders and strengthen our balance sheet at the same time. We repurchased 5.6 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 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 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 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. 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. 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 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, 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. 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 as 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. 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 U-turn wells, which involves utilizing a high-performance mud motor to drill complex wells shaped like a U, 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 Mpact mud motors and Mpower MWD 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 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. With that, I will now turn the call over to Andy Smith, who will review the financial results for the first quarter. Thanks. Net income for the first quarter was $99.7 million or $0.46 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 $2,430 over the previous quarter to $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 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 $1,000, 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 in the calendar. Pressure pumping revenues were $293 million, with an adjusted gross margin of $73.2 million. 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. In 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 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 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. 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 reactivations, which is now expected to be $180 million, down from $200 million. Included in our forecast for rig reactivation CapEx is the reactivation of six rigs throughout 2023. All are currently contracted. All six of these rig reactivations include very specific packages requested by the customers, including emission-reducing upgrades such as natural gas engines or utility skids for highline power. 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, 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 a spread to Tier 4 dual -fuel. 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 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 longstanding 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. 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. Thank you. To ask a question, please press star one. Your first question is from Jim Rollyson of Raymond James. Please go ahead. Your line is open. Hey, good morning, guys. Nice quarter. Thanks, Jim. 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, you know, the continued kind of evolution of frac fleets to dual-fuel or electric, you know, basically tied to gas because of the huge fuel cost savings that especially is around today. You mentioned you're adding, you know, upgrading another fleet this year, so that should put you to nine out of 12 by end of the year. Are you seeing a discernible kind of pricing difference for between the two, you know, the old Tier 2 diesel fleets versus the newer generation Tier 4 dual-fuel? Is it more just what's in customer demand that drives those decisions? I'm kind of curious on a short-term basis. First, we continue to do the upgrades. It's been in our program now for over a year. 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 gonna be Tier 4. That's the starting point. 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. The benefit for the E&Ps, of course, to be able to burn as much natural gas as they can when they can bring natural gas to the pads. You know, this is an ongoing process. It's part of our maintenance CapEx. I mean, it is an upgrade process, the real upgrade is not just the Tier 4 engine. That's part of the maintenance and replacing older Tier 2s. The upgrade portion is really just adding on the dual -fuel kit, which is a smaller portion of the capital. It's primarily part of the maintenance budget. you know, we think it continues to improve the quality of our fleet. The number of spreads, you know, that'll run dual -fuel are gonna be increasing for us, and we get a bit better margin when we do that because there's a huge benefit to the E&P. Excellent. That's helpful. Then just as a follow-up, you know, 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 into the second quarter or through the second quarter based on guidance. One of your peers mentioned, you know, the strength continuing in the oily basins, but obviously they were talking about some price degradation in rigs in the gassy basins. I'm curious just if you've... You know, 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. Yeah. I'm sure we're gonna get a few questions on, you know, what day rates are doing and pricing. It's really about what we choose to do in the market. You know, our choice is that, you know, we don't see a need to reduce the rates on the rigs. You know, 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 basins, given the demand that's gonna occur for LNG and feeding LNG trains and systems. We just don't see the need to reduce the rates. You know, we still see demand in the oil basins, with any slowdown in the natural gas basins, we'll just wait and work those rigs when that activity starts to pick up again. Makes perfect sense. Thanks. Your next question is from Saurabh Pant of Bank of America. Please go ahead. Your line is open. Hi. Good morning. Good morning, Andy and Andy. Good morning, Saurabh. 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? I can't help but ask because it's such a contrasting outlook for the second quarter. A couple of your peers, big ones, reported earlier, they're talking about a 9%-10% decline in their activity 1Q to 2Q. On your numbers, it sounds like your activity is expected to be down just 2%. Why do you think you're doing so much better? Is it about your basin or customer mix? Is it just about the way the rigs roll off contract? Is there something else? Because the delta seems just too much for what we have historically seen. I just want to clarify that please, Andy. Yeah. I think, you know, 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, you know, Bakken oil, we've seen some slowdown. In Mid Con, you're producing for both oil and gas, and rigs drilling for gas. We've seen some slowdown in the Mid Con. South Texas, you've got a mix of rigs drilling for some oil, some gas. Of course, you got Haynesville covering, you know, East Texas and Louisiana. You know, 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. You know, that's a gas basin that's, as all of y'all well know, is, you know, a bit segregated from the rest of the pipeline structure in the U.S., and that services the Northeast industrial and heating market. 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. While we operate there, we have less weighting in those basins. I think it's, just, you know, the basin weighting for different drilling contractors on how things are being affected right now. Okay. Okay. No, that makes sense. Then just quickly on the pumping side, I think you talked about white space going up. Obviously spot market looks like it's a little looser than it was three or six 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 space, taking a let's say near term hit to profitability, right? Like you said, this might be a pause and things might start to get better. How do you think about just taking a short-term hit on profitability due to white space versus just saying, "I'm going to stack one of my 12 fleets that are working out there?" It's, you know, 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. You know, we are gonna have to work through some white space, and that's gonna bring down margins a little bit. 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 then the Northeast where we do a lot of the Utica at higher pressure, higher rates. In those markets, you know, we're seeing pricing holding steady, and it's really the white space that's affecting us. We've got customers that are pulling back on their schedules, and we're just gonna have to adjust with that for now. Again, I see it more as a pause, 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. Okay. Okay. Okay. Perfect, Andy. Thanks for those answers. I'll turn it back. Your next question is from Kurt Hallead of The Benchmark Company. Please go ahead. Your line is open. Hey, good morning. Good morning. Yeah. Quite a radical differential relative to some of your other peers. Excellent execution, Andy. Congrats to everybody there. Hey, just kind of curious, right? As you reference the dynamics first on the drilling front, you know, with your exposure more to the Marcellus than maybe to the Angel and some other areas. Understanding the structural differences of that market, but also understanding that your customer base will, you know, take every opportunity to kind of chip away, you know, and get better terms and better pricing. W ould you give us some insights as to, you know, the discussions you've been having lately, and has the typical friction around discussions on pricing? Have you seen any change in that whatsoever? Have the E&Ps got a little bit more aggressive than they have been in recent quarters? You know, Kurt, it's certainly the E&Ps have to do their job and they have to ask. I wouldn't say things have necessarily gotten more aggressive. You know, especially in some of the more challenged gas markets like the Haynesville, you know, which have been more affected by gas prices coming down. You know, either it makes sense to drill a well or it doesn't. You know, us reducing the day rate on a rig by 10% or 15% is not gonna boost the economics to get a well drilled. I wouldn't say we're seeing a lot of pressure. I would... You know, it's really more of the challenges in some of the basins that I was mentioning earlier, you know, around Mid Con, South Texas, and the Haynesville, you know, where you've got gas production, where we're just seeing some slowdowns. You know, we're gonna 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. You know, we've got some moving pieces in our rig count, but for us, the net is we're only gonna be down a few rigs. It's really kind of where we're positioned in the basins today. In terms of aggressiveness, you know, I wouldn't say that we're seeing it so much. Again, like I was saying earlier, it's about our choice. You know, we choose not to work at the lower rates. You're probably gonna hear some anecdotal evidence of some drilling contractors that are lowering some rates. You know, we think very highly of our teams and of our rigs and, our, you know, our pressure pumping equipment, and we just don't feel the need to do that. Okay. That's good color. Follow-up on the frac side. You obviously spelled it out, you're gonna have nine exiting this year, nine of your 12 frac fleets will be dual -fuel. I'm just kind of curious, you know, as the market's evolving here and, you know, clearly moving toward the dual-fuel for obvious, you know, cost reduction and efficiency gains, and et cetera, what's your take on electric frac fleets and, you know, maybe longer term, Andy, you know, how would you see, you know, the mix of your assets? Yeah. I'll lump electric into, you know, various new technologies that employ natural gas as the primary fuel. I think that 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. We'll keep you posted on what we're doing later. You know, 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 gonna happen in this environment, and we just haven't seen it. 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 Podhaizer of Barclays. Please go ahead. Your line is open. Hey, good morning, guys. I just wanted to go back to the comment around, seems like your rig count's a little 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 contracts, 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. Yeah. Derek, good morning. It's tough for me to really say, you know, what our term versus spot is relative to our peers, 'cause 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. You know, our weighting is more towards the Permian and the Northeast on the drilling rigs and even on the pressure pumping. You know, we're seeing steady work up in the Northeast in that gas basin. You know, over time, I think we're gonna see increasing activity in the Permian, especially depending on where, you know, oil goes. If oil goes back over $80, then yeah, 100% you're gonna see the rig count and the 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, you're expecting the rig count to increase here, so maybe bottom out over the summer months and then increase. 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 to come onto work? Just maybe a little bit of help around what gives you the confidence to see rigs going up in the back half? You know, it's really around discussions with customers. You know, even if what we're doing in the natural gas basin stays relatively flat, I think that, you know, throughout the year you're gonna see the potential to increase in the oil basins, that's gonna drive a lot, you know, a lot of that. Of course, where the commodity is gonna drive the rate of increase, and we'll see how that plays out, you know, over the next few months. On the natural gas side, in discussions with some of the customers, we do have customers that anticipate that they're gonna need to get well inventory in the ground for the upcoming demand on LNG. You know, that's gonna happen, you know, towards the end of this year and into 2024. You know, we do see this natural gas, you know, reduction in activity as a pause more than anything else. Great. Appreciate the color. I'll turn it back. To ask a question, please press star one. Your next question is from John Daniel of Daniel Energy Partners. Please go ahead. Your line is open. 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? For us, this is a pretty short discussion on the price of the rig. I mean, the price is what it is. You know- Okay. ... we think that, where the rig rates have moved over the last year is where, you know, they need to be. Really pleased with how, you know, we continue to be able to reprice older contracts from last year, you know, at current rates this year, which is, you know, gonna improve our margins quarter on quarter this year. For us, you know, with the type of rigs we operate and the performance track record, you know, of our teams and the technologies they're employing on the rigs, you know, the day rate is the day rate. Fair enough. Well, to your, to your credit, the larger players have been, you know, as you know, more vocal about defending price. I'm curious if when you go, let's say we're six months from now and we're looking at the overall rig count change, are we gonna 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, has the overall rig count declined a little bit less than maybe what some of the guidance is from the top four guys? If that makes any sense. You know, it's hard for us to look at the overall rig count these days given, you know, our coverage with customers and, you know, we don't provide SCR mechanical rigs. We've seen those come down fast. We've seen those come down. You know, we saw a lot of those rigs being used by private equity backed, you know, E&Ps that were trying to prove up acreage and, you know, they're trying to manage their P&Ls and their valuation. I could see those rigs coming back and potentially, you know, taking share away from, you know, the larger drilling contractors, the public drilling contractors that are using super-spec rigs. It is what it is. It doesn't affect us. Okay. Last one's more of an operational question. You know, Matador called out the U-shaped lateral in their earnings, and you obviously reference it too. I'm assuming maybe you're working for them. I'm curious if, 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? Yeah. For, for the, for the jobs that I know of that we're doing the hydraulic fracturing on the U-shaped wells, I'm not aware of, you know, any difference on how we operate those versus, you know, just a straight lateral. We've done the U-shape for a few different E&Ps. You know, certainly the public data out there that shows that we work for Matador and really pleased to have them as a customer, and pleased to be able to trial some of these new technologies with them. Fair enough. I guess I'll just dumb it down so I can understand it. If you were doing two 5,000 -foot laterals and just make up a number, it took four days for each of those two 5,000 -foot laterals to complete. Is it now seven by doing the U? I'm just trying to see if there's enough, a savings in job time. It's really because you're drilling in a you know, you're working in a single section, and you're trying to maximize your exposure to the reservoir in that section. You know, it's two 5,000 -foot laterals, plus you've got the, you know, the turn on the U where you've exposed reservoir there and some operators will frack that section of the U as well where we do the turn. It's not necessarily that you're doing that to improve efficiency. It's because you're constrained by lease lines in a 5,000 -foot square section. Okay. Fair enough. Well, thank you for including me. Yep. Thanks, John. Your next question is from Don Crist of Johnson Rice. Please go ahead. Your line is open. Morning, gentlemen. Thanks for letting me in. Just one quick question on broader base 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? 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, you know, rigs could move, a large amount of rigs could move in the Permian per se and kind of affect spot pricing there? Yeah, good morning. To begin with, we have stacked, you know, natural gas rigs in natural gas basins. We had, that's already in the public data that we've had some, you know, rigs come down in the Haynesville, and we've just chosen to stack it there. We think that, you know, 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. Do I think that rigs will move? Rigs will move when E&Ps pay for the mob. There may be cases where rigs move from some basins to other, but, you know, 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 gonna be in a large number right away. I would say that, you know, if there are some drilling contractors that get aggressive on price, they're in a different situation. You know, 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, You know, 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. We don't have to choose those rates. We choose not to take those rates. Okay. If I could sneak in one other one. You know, obviously the rig count is coming in a little bit. Are you seeing any movement on steel or labor or any other kind of cost input, you know, given that there's more people available, et cetera? Labor is what it is. It's still relatively tight. You know, 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, you know, 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-end specialty pipe that has a long lead time. 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. You know, overall there are some, you know, cost savings that E&Ps are getting. It's gonna be around their casing, it's gonna be around sand in some cases. I don't see big changes in the service rates. Okay. I appreciate the color. Thank you, Andy. Thanks. 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 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? How might you expect that to change throughout the year? Yeah. We have about a quarter of what we do that has some spot market exposure. You know, we're seeing some white space in the calendar. You know, I don't expect any real change throughout the year there. You know, when I say spot, you know, that could still be for a period of time, not just, you know, two wells, three wells at a time. You know, there is some continuity even in that spot market. We just are seeing a little bit more white space. It's not, again, affecting, you know, service pricing per se. It's really just, you know, affecting margins because of the way things are falling in the calendar. Got it. Thanks for that. No, 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, you know, that kind of precludes you from putting together an additional fleet next year? 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 this year? You know, the upgrade to the Tier 4, again, is part of our maintenance budget. You know, that's coming out of the maintenance CapEx. Then, you know, the addition of the dual-fuel systems, I consider that more an upgrade where we're gonna try to get, you know, better rates for that, and I think the market still supports that. You know, again, no plans to reactivate, but that's really based on looking at current market conditions. Now, if oil moves over $80 and it stays there for a, you know, fair period of time, that could change the dynamics going into 2024, and we could see some demand from existing customers today. I think we just have to wait and see how this year plays out. I think a lot of it'll be driven by, you know, what the commodities do, you know, throughout this year. Understood. Thanks very much. Thanks. Your next question is from Kurt Hallead of Benchmark. Please go ahead, your line is open. Hey, I got quick follow-up. Sure. Coming back around to the other Andy's financial guidance. If I do my math correctly, looks like gross profit and operating income should be roughly flat with first quarter. Am I looking at it the right way? On a consolidated basis? Yes. Yes. Hang on one second. Think that's about right, but let me pull something up here real quick. Yeah, that's right. Awesome. All right. Appreciate that. That's it for me. Thanks. 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. I was gonna say we're getting ready, John. I couldn't waste an opportunity. Thanks Thanks for bringing me. I'm just so excited to talk, Andy. 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? When the market recovers, the timing and the cost- The timing and cost to bring rigs back out. Yeah. Timing, relatively short. Cost, relatively low. You know, we don't necessarily consider that, you know, a reactivation that we've had to budget growth CapEx for because if a rig's only down for, you know, a few months, we don't have to do much to it. Okay. ... it's not the same economics as if we're reactivating a rig that's been down for two years. You know, in our CapEx budget, we've got reactivations in there where it was around $2 million to bring back a rig that's been down for a couple years, and then some of those rigs have upgrades on top of that, and so we considered that growth CapEx. You know, 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. Thanks, John. I will now turn the call over to Andy Hendricks for closing remarks. Well, I'd like to thank everybody who joined us on the call this morning and 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. You may now disconnect.