Ladies and gentlemen, thank you for standing by. My name is Abby and I will be your conference operator today. At this time, I would like to welcome everyone to the Patterson-UTI Energy First Quarter 2026 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 that time, simply press star followed by the one on your telephone keypad. If you'd like to withdraw your question, press star 1 oneagain. Thank you. I would now like to turn the conference over to Michael Sabella, Vice President of Investor Relations. You may begin. Thank you, operator. Good morning and welcome to Patterson-UTI's Earnings Conference Call to discuss our first quarter 2026 results. With me today are Andy Hendricks, President and Chief Executive Officer, and Andy Smith, Chief Financial Officer. As a reminder, statements that are made in this conference call that refer to the company's or management's plans, intentions, targets, beliefs, expectations, or predictions for the future are considered 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 takes no obligation to publicly update or revise any forward-looking statements. 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. I will now turn the call over to Andy Hendricks, Patterson-UTI's Chief Executive Officer. Thank you Mike and welcome to our first quarter earnings conference call. I'm going to begin by saying we're hiring. Now let's get started. The first quarter of 2026 built on our momentum from 2025 with strong field execution supported by our technology and digital offerings across our diversified drilling and completions businesses. Our team stayed focused on the same priorities that drove last year's results, staying close to customers, delivering high-quality services and products that help them operate efficiently, and aligning CapEx and operating costs with the opportunities ahead. We are proud of our performance and believe our position across all our businesses will allow us to continue delivering strong cash returns across a range of market conditions. The commodity outlook has shifted materially since the start of the year due to heightened geopolitical risk and oil supply disruptions in the Middle East, which will likely reshape global oil supply and demand balances for several years. These developments underscore the strategic importance of U.S. oil and natural gas production and reinforce the need for a diversified global energy supply base with U.S. shale production more critical than ever. Over the past several years, even as expectations for U.S. shale activity have fluctuated, we have remained focused on operational excellence in our core businesses. We have consistently believed that excelling in our core operating businesses is critical to enhancing shareholder value regardless of the macro environment. Today, we are pleased with the efficiency of our operations and as U.S. shale activity inflects higher, we believe the decisions we have made position us to capture outsized value from a higher U.S. rig count. As a predominantly shale services company, we will always evaluate opportunities to deploy capital and expand our exposure to other geographies and product lines. However, we will remain disciplined and focused on returns for any potential growth investment. Momentum appears to be shifting back toward U.S. land activity over the coming quarters. Our corporate priorities remain unchanged. We will continue investing in technology and equipment that differentiates our services and supports long-term free cash flow per share while maintaining capital discipline, balance sheet strength, and consistent returns of capital to shareholders. We are well-positioned to execute on these priorities. From a macro perspective, the outlook is improving. Though the pace of a recovery remains somewhat difficult to predict, we believe the industry will need to increase drilling and completion activity just to maintain oil production. With oil prices now running significantly above the mid-December levels assumed in many customers' 2026 budgets, we are encouraged by the setup for higher U.S. drilling and completion demand. Some customers have already started to make plans for higher activity levels later this quarter, and we are increasingly hearing that the strip is likely to incentivize additional incremental oil-directed drilling and completion activity in the H2 of this year. The current WTI strip exits 2027 at approximately $70. If those prices hold, higher activity into 2027 becomes more likely. As is typical, private customers are moving faster than the publics. Natural gas activity also appears likely to improve as newly commissioned LNG facilities drive higher export volumes. While some of the incremental demand may be met by additional pipeline capacity from the Permian Basin later in 2026, we believe additional drilling and completion activity in gas-focused basins will be needed to fully supply that growth. As a result, we believe natural gas-directed drilling and completion activity is likely to increase in 2027. In our drilling services segment, we are very pleased with how the first quarter unfolded. Pricing remained steady, reflecting the value customers place on performance and reliability. In addition, the cost control programs we implemented towards the end of last year continued to gain traction and provided meaningful support to results. Because customer programs typically adjust with a lag to changes in commodity prices. Activity for some customers in the H1 of the year continues to reflect prior budget assumptions. We are seeing conditions improve, and we expect momentum to build through the quarter. We expect our rig count will exit the second quarter above the quarterly average and near the high point so far for the year, around 92-95 rigs, depending on the timing, positioning us well as we move into the H2. As E&Ps continue to drill deeper zones and extend lateral lengths, the importance of rig capability and contractor performance continues to grow. The number of the most capable rigs, those with the load-bearing capacity and pipe handling systems required for today's deeper and longer, more complex wells, remains limited and driven by investments from the best-performing drilling contractors. With our in-house engineering expertise and disciplined approach to upgrades, we believe we are well positioned to gain share in this growing market in a capital-efficient manner. As rigs become larger and more technical, we expect this to strengthen our competitive position and support higher returns over time. Our completion services segment delivered solid results for the quarter, despite disruption from a January winter storm that effectively paused the completions business for five days. Excluding that impact, our frack operations ran near capacity, with our natural gas-powered assets near fully utilized. Demand for completion services is improving, particularly in the back half of 2026, and we are in discussions with customers on higher pricing to more appropriately reflect rising demand and the high industry utilization. Available frack capacity across the industry is limited, and the few fleets that could be reactivated are among the industry's oldest and least efficient. At current pricing, reactivation does not seem economical, and pricing would need to rise meaningfully to incentivize incremental supply as demand increases. While our completions business has nearly 250,000 cold-stacked horsepower that could technically be reactivated, we have been clear that our priority is to invest in newer technologies that will drive long-term returns. Our cold-stacked equipment represents the oldest diesel equipment in our fleet, and reactivating a single fleet would require more than a $10 million investment. While the equipment could likely find work in the current market, the long-term return potential remains uncertain, and we are not prioritizing investment in these older assets. Over the past several years, we have high-graded our fleet by investing in newer, natural gas-powered technologies that we believe will remain in demand and generate strong returns for years to come. We continue to expect our nameplate horsepower to decline this year as we execute this high-grading strategy. Over the past several years, the frack industry has seen consolidation and bifurcation of equipment quality and efficiency. Lower-tier pricing has constrained cash generation for smaller peers, limiting their access to capital and slowing investment in new technology. This dynamic continues to widen the gap between industry leaders and the broader peer group, supporting a more rational and stable market with structurally higher returns over time. We expect our nameplate horsepower to continue to decline. We are directing capital toward expanding our Emerald Fleet of 100% natural gas-powered assets. By year-end, we expect more than 15% of our active horsepower to be powered entirely by natural gas, with approximately 90% powered at least partially by natural gas. We believe we have one of the highest quality fleets in the industry, and this transition reflects our ongoing focus on improving operational performance. In our drilling products segment, the team delivered solid performance despite several industry headwinds. The conflict in the Middle East has increased risk in one of our key regions, which contributes roughly 10%-15% of segment revenue, primarily from Saudi Arabia. Land activity in Saudi Arabia largely tracked expectations during the quarter, although activity in certain regions was impacted. On the cost side, we've experienced meaningful inflation in several key inputs, particularly the material tungsten, where prices are significantly higher than a year ago. In addition, our Middle East operations have seen higher logistics and personnel costs due to the ongoing conflict in the region. Even with these challenges, our drilling products business delivered only a modest decline in adjusted gross profit versus the fourth quarter, and we are actively pursuing additional actions to further mitigate these risks. From a competitive standpoint, we are encouraged by our position. We are pleased with the team's performance, and we believe we have grown to record market share in several key markets, including Saudi Arabia. In the U.S., we also believe there's additional upside with several large customers. Overall, our teams executed at a high level in the first quarter, maintaining a discipline focused on service differentiation, capital allocation, and cost control as we navigated a demand environment shaped by customer budgets built on a crude oil price deck well below the current strip. We believe the indicators increasingly point to a period of higher commodity prices. Based on our customer conversations, we expect this to drive an increase in U.S. shale activity starting later in the second quarter and continuing into the H2 of the year. Even if oil prices moderate somewhat from current levels, we would still expect upside versus today's activity. As we approach an inflection in U.S. activity, it is worth briefly reflecting on the strategy we have followed the past few years. While we continue to evaluate opportunities to expand beyond our core markets, our priority will always be return on capital driven, and we've yet to find compelling opportunities that have cleared our investment threshold. We remain focused on strengthening our competitive position in our core businesses and improving efficiency, operationally and financially. As we've always said, we believe disciplined capital allocation and continuous improvement in our existing businesses are important ways to enhance shareholder value. With activity now inflecting higher, the decisions we have made the past several years position us to deliver improved performance going forward. We are pleased with where the company stands today and are confident in our ability to continue delivering strong capital returns to shareholders. I'll now turn it over to Andy Smith, who will review the financial results for the quarter. Thanks, Andy. Total reported revenue for the quarter was $1,117,000,000. We reported a net loss attributable to common shareholders of $25 million, or $0.06 per share. Adjusted EBITDA for the quarter totaled $205 million which included $3 million in early contract termination revenue in the Drilling Services segment. Our weighted average share count was 380 million shares during Q1. As expected, seasonal working capital headwinds impacted free cash flow in the first quarter. Given the timing and variability of these items throughout the year, we view full year free cash flow as the most meaningful measure of performance, with working capital turning into a tailwind in the second half. In our Drilling Services segment, first quarter revenue was $352 million and adjusted gross profit was $134 million. Revenue and adjusted gross profit included the previously mentioned $3 million of early contract termination payments. In U.S. contract drilling, we totaled 8,301 operating days in the quarter, with an average operating rig count of 92 rigs. Excluding early termination revenue, pricing was relatively steady versus the fourth quarter, and we continue to see benefits from the cost reduction actions implemented late last year. For the second quarter in Drilling Services, we expect our rig count to average around 90 rigs, and we expect to exit the quarter above the average as we reactivate rigs in the back half of the quarter. We expect adjusted gross profit in the Drilling Services segment to be approximately $130 million. Our guidance includes $5 million of rig reactivation and mobilization costs and assumes minimal second quarter revenue contribution from those reactivations. In our Completion Services segment, first quarter revenue was $680 million, and adjusted gross profit was $98 million. Results reflected the impact of roughly five days of winter storm impact in January. Excluding that disruption, our frack calendars were essentially full, with limited spare capacity to increase activity and an extremely efficient calendar. For the second quarter, we expect completion services adjusted gross profit to be approximately $105 million, with near full utilization of our active assets. First quarter drilling products revenue was $80 million, and adjusted gross profit was $33 million. Results reflected disruption in the Middle East related to the ongoing conflict and some cost inflation. For the second quarter, we expect drilling products adjusted gross profit to decline slightly, driven by lower profitability in our international business, particularly in the Middle East, and the normal impact of spring breakup in Canada. Other revenue was $6 million for the quarter, with adjusted gross profit of $3 million. For the second quarter, we expect other adjusted gross profit to be approximately $5 million. General and administrative expenses in the first quarter were $69 million. For the second quarter, we expect G&A to be approximately $67 million. On a consolidated basis in the first quarter, depreciation, depletion, amortization, and impairment expense totaled $218 million. For the second quarter, we expect it to be approximately $220 million. During the first quarter, total CapEx was $117 million, including $54 million in drilling services, $45 million in completion services, $16 million in drilling products, and $1 million in other and corporate. We ended the first quarter with $337 million of cash on hand and nothing drawn on our $500 million revolving credit facility. We have no senior note maturities until 2028. Our board has approved a quarterly dividend of 10 cents per share, payable June 15th to shareholders of record as of June 1st. I'll now turn it back to Andy Hendricks for closing remarks. Thanks, Andy. I want to close the call with some additional comments on our company and the industry. The commodity outlook has shifted meaningfully since the start of the year, with both current and future oil prices now well above the assumptions embedded in our customers' initial 2026 budgets. While many customers remain cautious in the near term, we are seeing a clear change in market tone, including more discussions around rig reactivations, stronger completion demand, and improving pricing across our businesses. Taken together, we have much more clarity on the market direction, and these dynamics point to a more constructive environment for activity and profitability. For Patterson-UTI Energy, even as we expect industry drilling and completion activity to inflect higher, we will continue to invest in our strategic initiatives to improve returns. In completions, we will continue to favor technology investments over investing in our older cold stacked equipment and investing at a measured pace into new assets that should generate stronger returns over multiple years. In drilling, we are executing a disciplined cadence of structural upgrades to support deeper wells and longer laterals consistent with where customer demand is trending. Digital remains central to our strategy and is embedded across all of our operations. With the changing market sentiment, we believe that technology upgrades will be well supported through favorable contractual structures to support accretive returns. Finally, while the macro environment has changed, our corporate priorities have not. We remain focused on generating durable returns and sustainable free cash flow through the cycle while returning capital to shareholders. Our balance sheet remains strong, and we expect to deliver another solid year of free cash flow in 2026. As we evaluate opportunities to deploy capital, we will remain disciplined and prioritize investments that offer the highest return potential. With that, I'd like to thank the men and women of Patterson-UTI Energy who work hard every day to help provide energy to the world. Abby, could you please open the lines for the questions? Yes. Thank you. If you have dialed in and would like to ask a question, please press star one on your telephone keypad to raise your hand and join the queue. If you'd like to withdraw your question, press star one a second time. If you're called upon to ask your question and are listening via speakerphone on your device, please pick up your handset and ensure that your phone is not on mute when asking your question. To be able to take as many questions as possible, we ask that you please limit yourself to one question and one follow-up. Again, it is star one to join the queue. Our first question comes from the line of Saurabh Pant with Bank of America. Your line is open. Hi. Good morning, Andy and Andy. Morning, Saurabh. Andy, I think your inbox is going to be full of resumes by the end of the day after listening to your first opening statement. I guess, Andy, what I was getting at is, clearly it sounds like the initial leg of the upside is being driven by the private completion of DUCs, which makes all the sense, like you said, right? That's how the cycle begins. Already we are talking about Patterson saying we are pretty much sold out on active equipment. Halliburton said the same thing. Liberty kind of saying the same thing, right? How are the publics, right? Maybe help us think about how are the publics thinking about when they want to add activity, how much they want to add activity, if they want to add activity, right? At that stage, what would the supply side of the equation look like? How much equipment, how much capacity we would have or not have on the sideline ready to come back, maybe both on the rig and the frac side, if you can talk to that? Okay. Let me see where I can start. To begin with, we're really excited about the opportunity to put drilling rigs back to work. Like I mentioned earlier, we think we'll be somewhere between 92-95 rigs as we exit the quarter based on timing of when things go out. That's going to lead to higher completions demand, as everybody understands, over time. The interesting challenge that we have in the industry, as we've said, we're sold out of our top-tier equipment. We're essentially sold out of everything that can burn natural gas. We certainly will see a demand for more capacity as we move through the year. Before we start adding more capacity, we're going to be very focused on returns and trying to improve pricing where we can. We'll be continuing the discussions that we're already having with a number of our customers on what that pricing should look like, given the tightness in the market and given the demand. You'll see instances over time, potentially, of where there's some trading of customers within the market. We're going to work on improving pricing, improving returns before we start adding capacity. I think that's really critically important, especially given how pricing and completions has been pushed down over the last couple of years. It's important for us, important for our shareholders, for us to improve the returns where we can before we start bringing more capacity onto the market in the completion side. Right. No, that makes a ton of sense, Andy. I'm glad your peers are taking the same approach, right? We've got to fix pricing first, and then we'll talk about bringing capacity. That's fantastic. Then my follow-up, Andy, is on just the way pricing would work. On the rig side, there's a contract book you have. What does the contract duration look like? How quickly can we expect higher pricing to show up in your numbers just based on your contract book, and the same thing on the frac side? How should we think about pricing reopeners, three months, six months, or are there still sufficient number of annual contracts where pricing would take time to reset? Yeah. I think the best way I can describe the pricing situation on the rig side is when we did the last quarterly conference call, we said leading-edge was in kind of the low $30s, and that had been down from the mid to low $30s. I think what we're seeing today is pricing that is starting to move up from the low $30s. I'm not ready to call mid to low $30s, but it's definitely moving up from the low $30s at the leading-edge with everything fully loaded on the drilling rig. We're excited about that. The other piece is, as we get these requests for these technology upgrades on the drilling rigs, be it structural, be it digital, that leads to an investment, and it's going to require a term contract. We're hearing favorable commentary from our customers that they're willing to do that as well. That'll lock in those returns for the investments that we have to make. We are seeing leading-edge pricing on drilling rigs starting to move up. On the frac side, we're in discussions with the customers today. We have anecdotal evidence out there where some of the customers have already given us 10% price increases. I think that's relatively small compared to how completions has been pushed down over the last couple of years. I think that given the tightness in the market, certainly from our side and what we hear from competitors, that pricing will move up towards the end of this year. It'll move up steadily over the next months through the end of the year. Got it. Andy, just to clarify very quickly, a majority of your frac contracts are on three-month, six-month kind of pricing reopeners. Is that right? It's a bit of a mix, and we have some spot work in the second quarter. We do have some contracts that are longer term where the pricing only resets every six months for some very large customers, and that's okay. We're happy to work for those customers. We've got some customers where you revisit it as frequently as every month. We've got a mix. I got it. Okay, fantastic. Okay, Andy, thanks for those answers. I'll turn it back. Thanks, Saurabh Pant. Our next question comes from the line of Derek Podhaizer with Piper Sandler. Your line is open. Hey, good morning. Maybe a first question on the rig supply. I think on the website, you're at 88 rigs today. You're talking about upwards of adding seven rigs by the end of the quarter. Just wanted to see how immaterial those expenses are to get those rigs back to work, and maybe how many more rigs would you have behind that would require real capital investments and all the upgrades, you're talking about deeper wells, longer laterals. I'm just trying to think through putting upward pressure on that low 30s day rate towards the mid-30s or even into the mid to high 30s like we saw last cycle, just thinking on a rig-by-rig basis and how the required capital cost would be to bring certain rigs back maybe after these seven or these 10. Just maybe some thoughts around that. Sure. I think that to start with, for the rigs that are going back to work, it hasn't been too long ago that they were working, but there are some costs incurred to put them back to work. From an accounting standpoint, we even have to capitalize some of the mobilizations too, and we've got some rigs that are moving in different parts of the country. That puts us at around $5 million in CapEx just to get everything back to work and put a number of rigs out through the end of the second quarter and into the third. It's just the way we account for it, but we also get revenue back from that. We get paid for the mobilizations too, but it comes through the CapEx line as well. As we move forward through the year, for some of the structural upgrades, we think that we have a relatively low-cost solution for a number of our customers out there. It could be in the range of just a few million dollars, and we can see paybacks in a year and a half on some of that, depending on the day rates that we get, and we'll lock that into term contracts. That'll start to push the day rates higher. I've said this before a number of times. When we get into the large structural upgrades that we do, the CapEx costs are significantly higher. When you look at the APEX XC+ rigs that we have working in the field today, which went through a large upgrade process, those day rates are pushing $40,000 a day. I think that in the market that we're in, we will be exceeding $40,000 a day towards the end of this year and early next year with those types of large structural upgrades. Got it. Okay, great. That's super helpful. I guess on the frac side, I know you've talked about that you're effectively sold out. It's going to take a lot to bring equipment off the fence just given its legacy diesel. Maybe talk to the white space in the calendar in 2Q. Has that been fully soaked up? How is second half firming up as far as your current frac equipment? Just trying to think through what needs to happen on your current active fleet as far as white space being soaked up for the remainder of the calendar year before you would consider adding incremental new builds or equipment into this market, understanding that's likely going to be next-gen 100% natural gas type of equipment. Yeah, this has been a very dynamic situation. I can tell you as of last week, there was some white space in the calendar that I think a lot of people wouldn't have understood given commodity prices today. As of two days ago, we've basically filled the majority of that white space. Hats off to the team in completions and working with the customers to fill that up. We see for completions that the second quarter is really kind of a transitory quarter, not quite the inflection that we're seeing in drilling, but then that inflection in completion comes right after that. We feel like as of today that we're fully loaded in the third quarter. I'm really pleased with what the team's doing, how they're working with the customers, how they've loaded up the calendar in the second quarter, considering how the overall U.S. rig count has continued to come down. Looking past the second quarter and into the third, without getting into numbers, we feel like we're fully loaded in the third quarter. Great. Very helpful, Andy. I'll turn it back. Thanks, Derek. Our next question comes from the line of Jim Rollyson with Raymond James. Your line is open. Hey, good morning Andy, everyone. Good morning, Jim. Andy, as you kind of look at this, you've been through a lot of cycles, seen a lot of these inflections. Thanks a lot, Jim. I'm curious. Not calling you old, just experienced. I'm curious, how are you thinking about this as we go through the next couple of years? You've been talking, among others, about how tight the market is underlying in frac for a while, beyond just the fleet count numbers and all that. I'm curious how you think the odds of getting all your pricing back to kind of where you were two, three years ago. I'm also curious, given what you guys have been doing on the cost side over the last couple of years, how does that translate into margins relative to like right after next year closed, you were kind of low 20s EBITDA margins in Completion Services. I'm just trying to connect the dots here to see where we might think margins trend over the next couple of years. A few things on completions and how it's going to play out in terms of margins and what are we going to do based on the tightness in the market. What's important for us right now is to try to constructively work with our customer base to get the pricing back in line for where we are in the market. Like I've mentioned, we've been pushed down in the completions pricing for the last couple of years, and for the shareholders, we need to get the returns back to a reasonable level. While we're still generating good cash flow, there's still an opportunity to get the returns higher. We want to do that before we start adding capacity. Now, at the same time, throughout this year, we've been adding the new Emerald pumps that are 100% natural gas burning pumps, and really excited about the uptake in the market. These pumps are really spoken for with various customers, even before they show up in our own inventory. It's been a measured pace to bring those out, and when we do bring those out, it starts to improve our pricing and returns as we introduce those into the various fleets. We don't want to add significant capacity to the market until we can structurally really try to move the pricing up back to where we think it needs to be to get our returns. Now, on the positive side, to be able to do this, as I've said, we also hear that a number of our competitors are near sold out too. With all the consolidation we've seen in the completions market over the last five years, it's just structurally in a better place. While we're all still competitive, I think there's a measured level of discipline in that market too, to try to improve that market for our shareholders before we start adding capacity. Makes sense. As I think about CapEx, you guys obviously set a budget at the beginning of the year, which was kind of implying a down year as we're all expecting, and things have changed. I'm just curious how you think about incremental capital to the budget. It's obviously returns driven, but just the order of magnitude so we can kind of think about that as this starts to inflect the other direction. Yeah. Hey, Jim, this is Andy. We're kind of, again, on the front end of this, and certainly the market conditions that we're in today look remarkably different than what we looked at during our budget cycle. Yep. We're looking at it. I don't really have anything to give you right now, but I will say that we're looking at places where we think there could be opportunity, and opportunity to maybe lean into what we think is going to be a pretty strong price environment. Yep, makes perfect sense. Thank you, guys. Thanks. Thanks. Our next question comes from the line of Scott Gruber with Citigroup. Your line is open. Hey, good morning, Andy and Andy. Hey, good morning. I want to stay on the frac pricing discussion, kind of topic du jour here. I want to dig in a little deeper just because historically, the frac pricing discussion was kind of a simple generalized one. Today, there's so much more differentiation in the fleet. It's really a stratified fleet. A couple questions, just thinking through how pricing could evolve from here. I guess to set kind of an upside scenario is probably not unreasonable to discuss today. Kind of ballpark, how much incremental pricing would you need to see on the direct drive and e-frac to support new builds that reflect fleet expansion and not just replacement? I think when we look at how we're deploying the new Emerald direct drive systems for 100% natural gas into our existing fleet, the economics for that are actually very good. The way we're pricing those and bringing them in are very good. It's equipment that we've had out there under contract or under agreements for the last year or so that we really need to bring that up to a level overall. We need to get our average up. It's not really about what we're getting for the new technology that we're putting out there. I think that's working really well, and I think we're getting the returns that we want out of that. I'm more concerned about what we're getting in the overall averages. I think that we're entering a very tight market for completions. As I've said for a while, and for a few quarters, we've been sold out of everything that can burn natural gas. Overall, the industry's about to enter a very tight market for completions, and I think that bodes well for all of us trying to get our returns up to acceptable levels. Then we can look at starting to bring in capacity increases of new technology. Yeah. I think the only thing that I would add to that is, kind of given where we are in the market right now and the premium that gas burning equipment gets today, I think we're seeing pricing improvement across the fleet, more so obviously on the gas burning stuff. As we look at that, combined with what is, we think, kind of a crystallizing version of the market over the next couple of years, or at least more visibility than we've had historically. I think you don't have to see a huge amount of pricing to be able to justify some new builds into this type of a market, but you probably still need 5%-10% additional. That makes sense. That's what I was going next is, that gap kind of between the Emerald kit and the dual fuel kit. I imagine there's a gap between Emerald and Tier 4 dual, and a gap between Tier 4 and Tier 2 dual. Any color you can give on those gaps? And as pricing improves, do those gaps compress, or do they kind of retain and everything kind of goes up because you have the diesel displacement rates kind of sustaining different economic advantage across the different type of kit? You're correct. There is various levels of technology, and there is a pricing differential between those levels of technology. The market situation that we're about to go in over the next six months is a rising tide that's going to lift all these boats. The differentiations is still going to be there. The differential on the pricing is still going to be there. Overall, pricing for all these levels of technology, I expect to move up. Yeah. Again, with the diesel gas spread, I think that while all pricing will move up, you may see the spread between the different levels of equipment widen, just in terms of the cost differential. Yeah. You could see Tier 4 utilization rise at a greater rate than Tier 2, is what you're saying? Yes. Potentially, yes. Yeah. Okay. That makes sense. Okay. Thank you. I'll turn it back. Our next question comes from the line of Stephen Gengaro with Stifel. Your line is open. Thank you. Good morning everybody. Good morning, Steve. Two from me, and one is on the same pricing discussion, but when we think about sort of the way the pricing contracts behave, given your positive commentary, would you expect to see a strong inflection point in margin in the third quarter for completions? You think it's more as kind of a smoother increase as you go through the next couple of quarters? How should we think about kind of when we see it on the income statement? I think it's going to be more of a smoother increase in pricing, not just over the next two quarters, but into 2027 as well. I think this is going to be based on, like I said, constructive negotiations with our customers. We're going to have customers call that want to increase their capacity. We're going to have E&Ps call that we maybe not working for today, and it's going to create new opportunities, and it's going to create negotiations with this customer base in general as to where this equipment goes. This is an interesting market for us, but it's one that we need to do the right thing for our shareholders and improve the returns. I think it's a steady process to do this over multi-quarters. Okay. Thank you. That's helpful. The other question I had was, when we think about on the drilling side, and you talked about some of the performance-based and, I guess, kind of packaging of products over between completions and drilling, how does that play out in a tighter market? Is it better for you? Does it give you more opportunity? Do you think a tighter market helps that approach or hurts that approach? How should we think about that? Yeah, we've actually seen over the last couple of years since we introduced this, and this is our P10 Advantage offering that we have for the E&Ps across drilling and completions. We've seen challenges because the market was getting softer. I've actually been in discussions with some mid-tier operators who say, "Look, hey, we may kick off a program, and if we do, we'd like to discuss with you what you can do for us," because for them at a mid-tier level, expanding their program, they don't necessarily have all the internal resources to do that. If we can help them on the efficiencies across drilling and completions, that's a positive for them. This will be a positive market for expanding that offering. I appreciate that you asked the question because as some of these mid-size E&Ps look to expand what they're doing, they're going to need help, and we are well-positioned to help them out. Excellent. Thank you for the details. Our next question comes from the line of Arun Jayaram with JP Morgan. Your line is open. Yeah. Good morning, Andy and team. Andy, your prepared comments suggest that the rig count is going to be trending up five to seven rigs as we think about in 2Q. I'd love to get a little bit of color on which U.S. shale basins are you seeing that incremental demand on the rig side? Interestingly enough, Arun, we're seeing it across multiple basins. It's not concentrated in any one particular basin. We've got customers that are in multiple basins looking at the economics that they have. It's oil, it's gas, it's across the board. It's broad, and that's actually quite encouraging that it's not concentrated into one basin. That means that there's further opportunities over the next few quarters and past that to expand the rig count as operators continue to look at their economics. Got it. Just maybe my follow-up. Andy, you closed your prepared remarks talking about evaluating opportunities to deploy capital. You talked a lot about the Emerald technology, the 100% natural gas-burning engines. In terms of what are you looking for at this point to add that, call it, incremental capacity? Your nameplate's actually going down this year, as you mentioned. What are you looking for in terms of market signals to maybe step up, I think, the CapEx guide's around $500 million or less. This year. What are you looking for to start, call it, deploying some growth capital in terms of the business? Yeah. Arun, I appreciate the question because, as everybody knows, we've been holding back some cash, looking for opportunity to deploy that cash, whether that was through increasing the dividend that we did here recently or buying back shares, which we did last year. We've also looked at opportunities in M&A as well. As this market improves, we now have even further options because, with an increasing activity and the demand that we're seeing on technologies, whether it's on the completion side with Emerald 100% natural gas, or it's on the drilling side with the APEX XC+ rig that we have, we've got to evaluate what that looks like from a return standpoint and what we think is the right answer for the shareholders as we start to deploy more capital. Great. Thanks a lot. Our next question comes from the line of Keith Mackey with RBC Capital Markets. Your line is open. Hey, thanks, and good morning. Morning. Morning. I think it's pretty rare to be talking about termination revenue and rig activation in maybe the same call. Can you just, maybe Andy, walk us through a little bit about those factors? Maybe it's a timing issue on the termination and then, with the rig reactivations, what type of CapEx or OpEx do these rigs need to come back? Is it a matter of increasing specification requests on behalf of the operators? Any color there would be appreciated. Yeah. This quarter, as everybody knows, has had a lot of moving parts to it. We've had E&P customers that started off the year with a budget at a certain level based on commodity prices at a certain level, and still under a lot of pressure from investors to keep CapEx in line and not overspend their budgets. Yeah, we've had rigs come down, we've had termination payments all in the same quarter that we're having discussions now to put rigs back to work. It's been quite the quarter to try to navigate how we're going to manage this and watch our cost base as well, because that creates challenges as the rig count's coming down, and then we've got to put a rig count back up to work, and it's in basins across the U.S. We've got rigs moving between basins, and so there's a lot of things going on in terms of the cost base to put the rigs back to work after they've come down. In terms of overall numbers to put rigs back to work, if they've been working, I'd say in the last year, then we're in probably a range of $2 million CapEx to put them back to work. There's certainly no upgrades that are less than $1 million in terms of technology. We're getting requests for structural upgrades. We're getting requests for some digital solution upgrades. It really depends on the customer, where they're working, what the objective is that they're drilling is to the capacity that they want it to do. That could potentially drive some more capital spend, but we're still evaluating that and just trying to make sure that we understand the market and that we work through those discussions with the customers, because as we spend those kind of dollars on upgrades, then we certainly want a contract to cover that. Yeah. Just to clarify all that, make sure that we understand. The rigs that we're talking about in the second quarter, we've included the $5 million of operating expenses to reactivate those rigs. That's OpEx, that's not CapEx. The CapEx is probably on rigs that would go to work, those rigs maybe are a little further out and haven't worked so recently. Got it. Appreciate that color. Maybe just turning to inflation. I think that certainly is a concern, and there's some obvious places where we might be seeing it, but what type of potential inflationary factors are you watching, and how much of that do you think you're able to mitigate? Certainly in a lot of areas. Of course, diesel prices moving up. The one thing that I will say is there's plenty of sand in the Permian Basin. We're not seeing any challenges around sand where we have a lot of completion activities today, in terms of the Permian. Maybe some of the smaller basins are starting to tighten up a little bit, but we expect that changes over time too, and that we're accommodated there. On the drilling product side, it's dealing with some of the materials that we have. We're basically saying that tungsten prices are moving up significantly right now. We're not the only industry right now, given what's happening in the world, that requires tungsten. We're seeing that move up, but we actually have ways to mitigate that. We use the tungsten in the matrix body bits, but if we start to produce more steel body bits, then we can mitigate the cost of the tungsten as well. Just a number of things going on, but there's ways that we can mitigate that. If there are costs that are moving up that we need to pass through to the customers, this is absolutely the right market to be able to do that in. We'll be looking at that as well. All right. Thanks very much. Thanks. Our next question comes from the line of Doug Becker with Capital One. Your line is open. Thank you. Andy, just wanted to get a finer point on how many rigs will be reactivated with the $5 million in costs. Is there line of sight to some term work, or you really just Seeing the spot market pick up to the point that gives you the comfort to deploy that capital? Yeah, I would say right now, nothing at that level yet. We are looking ahead to the year as to what the needs might be in the H2 of this year and going into early 2027 and having those discussions with customers. We'll certainly give you more information at the next quarter. When we talk about $5 million, that also includes mobilization costs as well, not just what we do to the drilling rig. The market is certainly moving in the right direction to allow us to do some potentially significant upgrades on technology, and maybe even take some share as we do this. We're excited for the discussions that we're in. We're excited for the market and the changing conditions. I've been optimistic through the year as we've been managing the business, but I'm far more than optimistic at this point in the market for where it's going right now. Yeah. Definitely. Just to make sure we clarify that $5 million ties to that 92-95 exit rate that we were talking about earlier. Got it. No, that makes sense. Maybe just a housekeeping item. You mentioned that Fern cost about five days on completion services. Just any EBITDA impact from that? On the winter storm? Yes. Yeah. It was about $9 million. That's what we saw. We had that included in our guidance when we gave it last quarter. We weren't quite as fine a point on it. We said $5 million-$10 million, but it ended up being at the high end of that range. Got it. Thank you. Our next question comes from the line of Eddie Kim with Barclays. Your line is open. Hi, good morning. Just surprised that the overall U.S. land rig count is still roughly flat since the beginning of the Iran conflict about two months ago, even as oil prices have increased substantially over that time period. Does that sort of reflect customers being in wait and see mode before deciding to pull the trigger on increasing activity, or more so maybe the lag between actually making that decision and actually standing up a rig? Just any color there. It does seem like, based on your outlook and your commentary, that the industry-wide rig count should start picking up here within a matter of weeks. Yeah, I'll start and then Andy can jump in and give you some more color. Our customers, just like we did, we went through a budget cycle and sort of all of this kind of came on right after we've kind of made our plans for the year. To change those plans on a pretty quick timeline without 100% surety where it was gonna end up or how long it was gonna last, would be pretty difficult, I think, to even ask of our customers. I'm not surprised kind of by the pace at which things have started to come back. That's my take on it. I don't know, Andy, if you have something you want to add to that. Yeah. Eddie, in the public data you can get on the rigs, what you can see is that some of the biggest E&P operators in the U.S. that you buy gas from really haven't changed their programs. They're just sticking to their programs right now throughout the year because that's what they've set their budgets on. I think that really will probably kind of stay that way. I think you'll see other publics, and I think you'll see privates start to move quicker, and that's what you're seeing in our rig count projections right now. These large E&Ps will re-look at their budgets for 2027, and that's why I'm also encouraged for next year as well. I think you're gonna see you've got some publics, you've got some mid-tier E&Ps, you got some privates that are all starting to rethink this year and with increasing rig count and increasing completion activity, and then the very large E&Ps will kick in for 2027. All right. That's very helpful color. Thank you. Just as it relates to your rigs, you mentioned exiting this quarter about 92-95 rigs. It seems like, just based on your commentary, that 2026 could almost look like a mirror image of 2025. At the beginning of last year, you guys were running about 105 active rigs. Do you think that 105 is achievable for you guys by the fourth quarter of this year? Or would that be too much of a stretch? I think it's too early to tell or try to project exactly what our rig count number's gonna be at the end of this year. We are encouraged about the discussions that we're having, that we will put up more rigs in the H2 after the second quarter. Very happy to be working in this type of market versus what we've been dealing with for the last year or so. Right. Great. Thanks, Andy. I'll turn it back. Our next question comes from the line of Dan Kutz with Morgan Stanley. Your line is open. Hey, thanks. Good morning. Morning, Dan. Maybe one on the international businesses that you guys have. Kind of looking past the near-term disruptions related to the conflict. Have you had any customer conversations or inbound in other regions outside of the Middle East or even any conversations with customers there that could indicate potential activity upside or any inbound on incremental demand for Patterson services and equipment, whether it's across the more global kind of drilling products business or you have the LATAM drilling footprint and the Turnwell JV in the UAE. Yeah, just wondering if you could share any thoughts or views or conversations that you've had about potential incremental upside in the international space. Thanks. Yeah. I'll give you some color on what we're seeing. I'll start with the Middle East from Kuwait on down to Oman. That's where we have a really solid drilling products business. We did see onshore activity relatively steady in those markets, especially Saudi Arabia and the UAE. Offshore, they did shut down a lot of the activity kind of midway through this conflict. That's had an effect. Also, particularly, in Saudi Arabia, our customer there was working through some of their inventory that they had still in their warehouses. I think that slowed product sales for everybody over there. At some point, that'll end, and then product sales will start to move up. With the onshore activity steady, we think we have some interesting opportunities over there. We are seeing some higher costs on logistics to get products and materials into the Middle East, and we've certainly seen a slowdown in Kuwait as well. We'll just have to see how a lot of this plays out. Moving over to South America, we did ship two drilling rigs down to Argentina. We do expect over the next one year to two years that in Argentina, the rig count continues to move up. We may get to participate more in that process. We'll see. It's too early to call anything out on that yet. We're in a number of conversations in Argentina. I'll just go ahead and mention Venezuela. Nobody's talked about Venezuela in a while. There is a number of interested parties looking at Venezuela to try to get in there and increase production, especially in the Orinoco Belt for the heavy oil. These discussions will take time, and I think that process will go very slow. As I mentioned, there are a number of interested parties. Great. That's all really helpful. Then coming back to the U.S., I'm not sure if this is something that you guys track or have noticed or have heard folks talking about, but just figure given your kind of unique footprint as a top both driller and frac service company, seeing some indicating that DUCs inventories are low, potentially even materially low, and obviously, that can influence the relative pace of drilling versus completions activity. At least from your remarks so far, it seems like you see upside in both markets, but just, yeah, wondering if lower DUCs inventories is just kind of structural and as efficiencies improve, or if you think that there's a dynamic there that could influence the pace of drilling versus completions activity. Thanks. Sure. I think, with the DUC inventory this year, what we've seen is that it's come down, and a lot of that is just directly related to the rig count coming down and the number of wells between the drilling rigs and the completion activity. With some of the smaller customers, what we've seen is that they've really kind of tried to pace themselves through the year. I'm talking about starting off at the beginning of the year where they drilled some wells and then they were going to complete them later. Some of those customers have called us based on current economics and said, "Hey, we want to frack these wells sooner." Where we could, we've tried to accommodate them. That's also led to some better returns on some of that work that we've done when we've pulled that work forward. I wouldn't say it's widespread yet so far. Now we're going into a period where the drilling rig count is going to start to move up. We're going to see the DUC inventory start to move up until completion activity moves up. With the tightness in the completion market, there could be a period that we are increasing DUCs even more than normal until we do get more completion work out there. I think it's going to be very positive for completions in the H2 of this year. Great. All really helpful. Thanks again. I'll turn it back. Thank you. Our final question comes from the line of Don Crist with Johnson Rice. Your line is open. Good morning, guys. Thanks for fitting me in here right at the end. Hi, Don. Andy, I just have one kind of macro question. We're hearing from some really smart people around the world, and given your contacts in the Middle East, that worldwide supplies are dwindling and the dichotomy between the physical markets and the financial markets for oil are pretty significant. With that background, we're hearing that the strip could increase pretty materially, despite whether or not this war is over sooner rather than later. I'm just curious as to your kind of macro view on oil and whether or not we ever go back to $65 or $70 oil, or if we do stay higher at call it an $80+ oil level for the coming years. I know that's kind of more philosophical, but just your thoughts. Well, Don, I really appreciate that macro question. I'll start by qualifying that I am not a commodities trader. There's some interesting things happening in the market. Before you get into the crude discussion, there's a real challenge in some of the refined products like jet fuel, kerosene, distillates, where those commodities have been ramping up at a faster rate than crude oil. I think that commodity traders on the crude side are kind of watching how these product sides trade to try to determine what the real cost per barrel should be. Because there is starting to be this disconnect between what traders' opinion are of what oil should trade at versus where you can physically get oil today and where you can move it to. We still, of course, have a bottleneck of crude, in terms of global production that's missing. That's going to have to get filled at some point, or it's going to have to start moving again, and that'll take months to work itself out. So I think where the strip trades today, looking forward, seems to be more of a best guess versus what the material price of a barrel of oil really is. It'll be interesting to see how that shakes out over the next year. Yeah. We're hearing from some really smart people that the strip is probably not going back to the $70 level again. We'll see. We'll watch it together. I appreciate the thoughts. Sure. I'm certainly encouraged by how our customer base is reacting and how they're discussing the forward strip, and the fact that we can tell you today that we're putting drilling rigs out. Exactly. Thanks for the time, guys. Thanks, Don. Our final question comes from the line of John Daniel with Daniel Energy Partners. Your line is open. Hey, thanks for including me. I completely flubbed and thought your call started at 10:00 A.M., so I apologize for being late. I've got three questions, and you might have answered all of these, and so I apologize if you did. From the supply chain perspective, Andy, specifically for drilling capital equipment, where are the longest lead times today? And do you see that being a limiting or delaying rig reactivations over the next several quarters? There are some long lead items. Some are close to a year. Those are some specialty items for some very large upgrades. That being said, we've already been placing some orders for some long lead items. We keep some things moving within the existing budget. When we talked about our capital budget at the beginning of the year, we talked about it's not just maintenance. We've got technology upgrades built in. We try to stay in front of some of these long lead items. I don't think the lead time really changes. They just are what they are on some of these long lead components that we've got to have, and we keep those on order where it makes sense. Okay. That being said, there's some shorter lead items too, around structural steel and things like that we can get at a relatively reasonable pace. I haven't heard anything from the teams, and we've had a lot of discussions over the last couple of weeks that gives me any concern that we're going to have trouble getting any of these types of items at the pace that we think we're going to need them. I think we're going to be fine on the technology and structural upgrades that we could potentially do over the next year. Okay. That's helpful. You touched on international Argentina and Venezuela. I'm curious, how do the rig specs differ between those markets and what you're doing here in the States? Just any operational color there would be helpful. Yeah, the good news for Argentina and Vaca Muerta is that you can take a drilling rig from the U.S. and you can move it right down there and drill one of the horizontals that they want to drill. That's an almost identical rig spec. When you get to Venezuela, you kind of have to break it up into which basin you're talking about. If you're talking about the Orinoco Basin and the heavy oil, we were drilling those wells 20 years ago with 1,000 horsepower rigs. Very easily you can take the 1,500 horsepower rig out of the U.S. and put it in there, and it's going to do better than we did before 20 years ago. You do have some deeper onshore plays where you need a 2,000 or 3,000 horsepower. I suspect that the focus in Venezuela is going to be on the heavy oil, because of the refineries in the Gulf Coast. The rigs in the U.S. will easily go down there and work there. Okay. Thank you. Final one. For the people, your employees that were in the Middle East, what percent of them left when the conflict started and what percent have returned? Just as the guy that kind of oversees all these people, how do you think about sending more people back, and when do you do that? Yeah. First I want to say, and they know who they are within the company, hats off to our enterprise response team. They were running a 24-hour operation to logistically check on everybody that we had from Kuwait all the way down to Oman, make sure that people were okay, comfortable where they were, assistance to move them out where they needed to get moved out. One of the bigger concerned areas was we had a number of rotators working in the field in the UAE. We had to get them out over land to Oman and then fly them out of Oman once the flights were working in a reasonable way. At this point today, we've got really everybody back to where they are. It's relatively business as usual. Okay. I say relatively because we do have concerns. The people that we have over there are comfortable working over there. If they're not happy working over there, we've certainly got work for them here. As I mentioned, we're hiring. We've got plenty of stuff going on. No, the people with it were happy to go back. Okay. Thank you for including me and for the time. Thanks, John. That concludes our question and answer session. I will now turn the conference back over to Andy Hendricks for closing remarks. Thanks, Abby. I just want to thank everybody that dialed in today for our conference call. It's an exciting time in the industry where we are seeing this inflection, and very happy to report this quarter that we're putting drilling rigs back to work, and that we have a good line of sight on completions for the rest of the year to be relatively fully loaded out. Thank you. Ladies and gentlemen, this concludes today's call, and we thank you for your participation. You may now disconnect.