Thank you for standing by. My name is Frilla, and I will be your conference operator today. At this time, I would like to welcome everyone to the Patterson-UTI Fourth Quarter 2025 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, please press star one again. Thank you. I would now like to turn the conference over to Mike 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 fourth quarter 2025 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 reconciliation to GAAP financial measures are included on our website at 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, and welcome to our fourth quarter earnings conference call. We closed 2025 with a strong fourth quarter, delivering steady results through what is typically a seasonally soft period. Our teams remained highly disciplined, with strong operational execution in the field and a focus on cost controls. We are pleased with the performance across all our businesses during 2025, particularly given the challenging commodity environment we faced throughout the year. Patterson-UTI once again demonstrated its ability to generate strong free cash flow, delivering $416 million in adjusted free cash flow in 2025. Notably, the fourth quarter marked our highest adjusted free cash flow quarter since we completed our strategic transformation in 2023. This achievement highlights our ability to adapt to changing market conditions and underscores the effectiveness of our teams in maximizing our potential throughout all phases in the cycle. We are showing greater resilience to market fluctuations as we use our technology edge to deliver operational excellence. I'd like to extend my sincere appreciation to all our employees for their hard work and dedication throughout 2025. Your efforts were instrumental in our success, and we look forward to moving Patterson-UTI forward again in 2026. The industry overcame numerous challenges in 2025, including an increase in OPEC+ supply and ongoing macroeconomic uncertainties. Despite these pressures, the oil market has remained resilient, with crude prices today at a similar, similar level to those on our last quarterly earnings call. Although commodity prices remain unpredictable, in any scenario, at Patterson-UTI, we will remain committed to our core principles: delivering safe and efficient execution for our customers, investing capital responsibly in differentiated technologies, and maximizing returns while generating substantial adjusted free cash flow for our investors. Our free cash flow profile continues to be robust, which gives us confidence to increase our quarterly dividend by 25% to $0.10 per share in the first quarter. We are confident that our free cash flow will exceed our dividend commitments, providing the opportunity for additional share repurchases or other investments aimed at creating further shareholder value. From a macro perspective, uncertainties remain regarding the sustainability of U.S. oil production at the current pace of activity. Recent data suggests that reduced drilling and completion programs in 2025 are beginning to impact production figures. The industry is likely approaching a point where it will need to decide between declining production volumes or increased drilling activity to maintain production trends. Although there may be a moderate decrease in U.S. oil activity in the near term, we do not believe that the industry can continue operating at lower drilling levels without causing a more significant impact to production than what has been seen so far. We remain optimistic about the long-term prospects for natural gas, and we anticipate that a multi-year increase in drilling and completion activity will be needed to meet future demand. While there have been some incremental increases in natural gas-focused activity and natural gas prices have rebounded sharply due to winter weather demand, we expect most large customers will wait for clear commodity price signals after peak winter demand before making changes to their plans. As physical demand for natural gas for both LNG and power generation grows, we expect to see additional demand for our services in the second half of 2026. In response to the macro environment, we have reduced our gross CapEx budget by around 15% to roughly $500 million in 2026. After accounting for the expected proceeds from a typical cadence of asset sales during 2026, we continue to expect that our CapEx, net of asset sales, will be below $500 million this year. We have made significant progress in lowering our unit-level maintenance CapEx requirements. We continue to successfully implement new digital processes that improve preventive maintenance, high-grade our asset base with new technologies, and consolidate facilities as we move further through the integration process of our businesses. Importantly, our 2026 CapEx budget reflects funding for high return projects that will further enhance the quality of our operations and ensure we are well-positioned with new technology that supports the next leg of customer demand. While we are substantially reducing our overall CapEx budget, we fully expect to exit 2026 with a more advanced and higher quality asset base than at the start of the year. During the fourth quarter, our U.S. contract drilling business saw relatively steady activity and pricing compared to late third quarter levels, and this stability continued into 2026. Our focus remains on identifying, investing in assets and technologies that bifurcate drilling performance and create unique value for both our customers and investors. Of note, we have seen increasing acceptance of performance-based commercial agreements, and this shift reflects growing customer interest in partnering with service providers who can enhance operational efficiency. Our ability to deploy advanced APEX rig technology that enables faster drilling of more complicated wells is resonating with our customers. We are also seeing strong results from the broader adoption of our drilling automation packages. Nearly all of our rigs are now equipped with our proprietary Cortex automation applications, and demand remains high as we continue to develop new software applications to further improve drilling operations, with many of these in partnership with our customers. Looking ahead, the evolving shale landscape is characterized by more complex well designs, requiring rigs with increased load capacity that can drill deeper geological formations, as well as longer and more complex laterals into higher pressure zones. Future demand will increasingly favor differentiated rig technology, positioning Patterson-UTI and our fleet of advanced assets and technology with a distinct advantage over much of the competition. The benefit of this differentiation has already been reflected in our ability to sustain margins at higher levels than we have seen during periods of activity moderation in prior cycles. As the market continues to favor high-quality drilling solutions, we anticipate that our advanced technology will further strengthen our position as we aim to sustain pricing and margins, as customers seek out the best available drilling contractor to meet their increasingly complex needs. In Argentina, we are excited with our recent agreement to lease two high-spec rigs for work in the Vaca Muerta field. The multi-year agreement is a capital-efficient way for us to put idle assets in the U.S. to work internationally. The opportunity in Argentina is one of the most promising that we see to put our idle assets to work globally, and our fleet of rigs in the U.S. are well suited to meet the region's growing demand for unconventional drilling over the next few years. The expansion also complements our established position in drilling products, including Ulterra drill bits in Argentina. We believe that further planned increases in drilling activity in Argentina will reduce the available supply in the U.S. Our completion services segment delivered strong results in the fourth quarter. Segment adjusted EBITDA for the second half of the year was higher than the first half, reflecting the quality of our operations and the steps we have taken over the past year to add new technology to our portfolio, streamline operations through our digital platform, and improve our cost structure. Our team effectively managed holiday downtime across several of our larger fleets, successfully securing work to maintain high utilization. Pricing and activity remained steady compared to the third quarter. Our frac assets remained highly utilized in the first quarter, with almost 2.5 million horsepower either deployed in the field or in normal maintenance cycles. We have very little spare capacity, and our idle horsepower consists entirely of older diesel equipment that is not part of our long-term strategy. As we direct our capital towards high-grading our asset base with additional Emerald 100% natural gas equipment, we are likely to have fewer fleets in operation as we continue to idle lower quality diesel assets and focus on the premium market. Our equipment that can utilize natural gas as a fuel is fully utilized. Our asset base will continue to reflect this high-grading strategy. Our nameplate horsepower totaled 2.7 million at the close of 2025, which is down more than 600,000 horsepower from two years, and we are likely to see a further reduction this year. Within our completion services segment, we continue to see growth opportunities in high-end natural gas-powered frac equipment and our industry-leading and proprietary Digital Completions Platform, which we call eos. Our Emerald 100% natural gas-powered footprint will grow again in 2026, and by the end of the year, we expect that more than 85% of our assets will be capable of using natural gas as a fuel in some capacity. We believe our asset quality is among the best in the industry, and the strong demand and returns for our high-end equipment position us to maintain resilient margins across our higher technology assets. We will reduce capacity of our older assets, and we believe the industry is also doing the same. Although public estimates of U.S. industry fleet count shows a decline, the total horsepower deployed has not declined and has remained roughly consistent. The frac industry is evolving towards larger fleets at the well site, a trend that we believe is being overlooked by public industry data on the number of active fleets, resulting in the frac fleet count becoming less of a reliable metric to determine industry completion activity. At the same time, the significant increase in pumping hours per day over the past several years has likely run its course. Some providers are encountering technical limitations on most of their fleets, with our average frac fleet now pumping over 22 hours per day. With continuous pumping, our team has been leaders in executing on the growing trend to achieve 24-hour operations. But continuous pumping fleets require significantly more equipment on location relative to a more normal operation, which increases the cost of continuous pumping and further restricts supply. We have successfully executed several continuous pumping jobs to date, as customers are currently evaluating whether the incremental increase in uptime justifies the additional cost. During the fourth quarter, we launched our proprietary eos Completions Digital Platform. eos connects our customers directly with their live field data, allowing the customer and our completions teams to improve real-time decision-making on the same platform. Our customers can eliminate the need for multiple third-party software platforms in their data flow and improve their overall data quality with a direct link to our Digital Performance Center. The eos platform is hardware agnostic, allowing our completions data and also third-party data sets to be delivered to customers on the same platform with no delays. The eos platform includes our advanced Vertex automated frac controls, which to date have been deployed across most of our active fleets and regardless of frac power type. eos also supports our other services, such as wireline, pump down, natural gas delivery, and proppant logistics. This takes our Completion segment to the ultimate goal of push-button frac, and soon with closed-loop decision-making, which will deliver more consistent completions to our customers, and over time, and lower our operating and equipment maintenance costs. We have revenue-generating agreements in place now and are seeing increased customer interest for deploying this platform. Our Drilling Products segment delivered another strong quarter in North America. Revenue per industry rig remained close to company record levels in both the U.S. and Canada, underscoring our robust market position in drill bits. Additionally, we are having continued success with new downhole tool product innovations, helping us to maintain relative strength in these markets. Internationally, revenue experienced a slight decline from the third quarter, primarily on lower-than-expected revenue in the Middle East. However, we achieved revenue growth in several important regions, including Latin America and Asia Pacific. Looking ahead, we remain optimistic that the international outlook for our drilling products segment will improve as we progress through 2026. We have opened a new manufacturing facility in Saudi Arabia and are now manufacturing drill bits in-country, which should give us an advantage as growth resumes in the Middle East. Patterson-UTI continues to look to extend our leadership position while the US shale industry undergoes significant changes. The company's operational excellence within both the drilling and completion segments has provided a competitive advantage, enabling effective navigation through the current commodity environment. Target investments across businesses will remain a central focus. These strategic efforts are evident in the company's ability to generate robust free cash flow and maintain relatively resilient margins, even through periods of activity moderation. Even with ongoing commodity volatility, we are well-positioned to deploy capital in ways that add value for shareholders, including through additional shareholder returns. We will continue to be flexible with capital deployment and evaluate a mix of dividends, buybacks, and other potential growth opportunities. 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 $1.151 billion. We reported a net loss attributable to common shareholders of $9 million, or $0.02 per share. Adjusted EBITDA for the quarter totaled $221 million. Our weighted average share count was 379 million shares during Q4. During 2025, we once again showed the cash generation potential of our company, with adjusted free cash flow totaling $416 million for the year. As expected, the fourth quarter was the strongest cash-generating quarter of the year by a wide margin. It is important to remember that given the timing of some working capital items, including significant customer prepayments that we typically receive in the fourth quarter for work to be performed during the first half of the following year, it is far more meaningful to analyze our free cash flow on a full year basis, as the quarterly results can show greater variability. For year-over-year comparisons, the customer prepayments we received in the fourth quarter of 2025 were roughly $15 million higher than those we received in the fourth quarter of 2024. Before we get into the segment discussion and the outlook, I want to give an update regarding the impact from severe winter weather that has already occurred during the first quarter. The January 2026 winter storm disrupted large portions of our operations for several days, and we believe the full impact of the disruption will have a negative impact on our first quarter adjusted gross profit, particularly in our completion services segment. The estimated impact of this event is included in the quarterly guidance numbers we will discuss. In our drilling services segment, fourth quarter revenue was $361 million, and adjusted gross profit totaled $132 million. In U.S. contract drilling, we totaled 8,596 operating days for an average operating rig count of 93 rigs. Our successful cost reduction measures mostly offset the revenue decrease during the quarter. For the first quarter in drilling services, we expect our average rig count to be in the low- to mid-90. We expect adjusted gross profit within the drilling services segment will decline by less than 5% from the fourth quarter. Revenue for the fourth quarter in our completion services segment totaled $702 million, with an adjusted gross profit of $111 million. Activity and pricing were mostly steady compared to the third quarter, with minimal seasonal downtime. For the first quarter, we expect completion services adjusted gross profit to be approximately $95 million, with slightly lower activity given the impact of the first quarter winter weather. Fourth quarter drilling products revenue totaled $84 million, with an adjusted gross profit of $34 million. Revenue per industry rig in the U.S. remained near company record levels. We saw a decrease in revenue from our international operations, mostly from lower than expected sales in the Middle East, although we did see revenue growth in several markets, including Latin America and Asia Pacific. For the first quarter, we expect drilling products adjusted gross profit to improve slightly, with slightly lower revenue in the U.S., offset by an increase in activity and revenue from our international business. As we move through 2026, we expect to see an improvement in international revenue in the drilling product segment as activity improves, primarily in Saudi Arabia. We also expect to see growth in downhole tools and new product development. Other revenue totaled $5 million for the quarter, with $1 million in adjusted gross profit. We expect other adjusted gross profit in the first quarter to be steady compared to the fourth quarter. Selling, general, and administrative expenses in the fourth quarter were $62 million. For Q1, we expect SG&A expenses will be approximately $65 million. On a consolidated basis for the fourth quarter, depreciation, depletion, amortization, and impairment expense totaled $221 million, and for the first quarter, we expect it will be approximately $225 million. During Q4, total CapEx was $139 million, including $61 million in drilling services, $59 million in completion services, $15 million in drilling products, and $4 million in other and corporate. For 2026, we expect gross CapEx to approximate $500 million and to be below $500 million net of asset sales. We expect CapEx will be weighted towards the first half of the year as we bring in new technologies into both the drilling and completion services businesses. We closed Q4 with $421 million in cash on hand, and we did not have anything drawn on our $500 million revolving credit facility. We do not have any senior note maturities until 2028. During 2025, we returned $192 million to shareholders through dividends and share repurchases. Since the start of 2024, we have returned roughly two-thirds of our adjusted free cash flow to shareholders for dividends and buybacks, and we remain committed to returning at least 50% of our adjusted free cash flow to shareholders. Our board has approved a 25% increase in our quarterly dividend to $0.10 per share, payable on March 16th to holders of record as of March 2nd. I'll now turn it back to Andy Hendricks for closing remarks. Thanks, Andy. I want to close the call with some comments on our company and the industry. I'm very pleased with how our segments performed in the fourth quarter, where we were able to show improvements in controlling costs and keeping them in line with the activity changes. This is a testament to focusing on what we do best, providing products and services to efficiently drill and complete wells. The result is that we were able to generate strong free cash flow to close out 2025. As well, I'm pleased to see this stable activity continue into the first quarter of 2026. The outlook for 2026 has the challenge of some commodity uncertainty. With oil prices trading near $60 per barrel, my expectation is that activity in oil basins remains relatively steady from where we are today. Oil markets have remained resilient, looking ahead to continuing economic growth along with some geopolitical unrest. Gas markets remain steady and have the potential for some activity upside later in the year. It's early to predict how 2026 will play out, but I'm encouraged by our current activity levels so far in the first quarter. We continue to invest in new technology in both drilling and completions, where we are seeing strong returns on our capital investments. In drilling services, we are being asked for new Cortex automation applications by our customers, along with upgrades to our APEX rig structures to drill deeper geological horizons and longer laterals. In completion services, we will continue to add new Emerald 100% natural gas fuel technology to our fleets and continue the rollout of the eos platform, which includes the Vertex automated frac system. In Saudi Arabia, Ulterra manufactured their first drill bit in-country in December, and this new manufacturing capacity, combined with our strong performance in the region and the planned increase in drilling in Saudi Arabia, gives our drill bit business some international upside this year. These technology and manufacturing investments allow us to continue to differentiate ourselves versus our competitors and maximize the margins we are able to earn. We're doing all this while reducing our overall capital expenditures in 2026. We remain focused on generating strong free cash flow for our shareholders, and over the last year, we have a higher level of cash than what is currently required to sustain our business. Given our cash generation potential, I am pleased that our board has approved a 25% increase in our quarterly dividend as part of our overall commitment to return cash to shareholders. With our current cash position and after capital expenditures, we will continue to repurchase shares in the market where it makes sense and also continue to look for growth opportunities. Once again, I'd like to thank the men and women, men and women of Patterson-UTI Energy for their outstanding performance in 2025, and for helping to responsibly provide energy to the world. Thank you for joining us today for our Q4 2025 earnings call. We'd now like to open the lines for Q&A. Thank you. We will now begin the question and answer session. If you have dialed in and would like to ask a question, simply press star one on your telephone keypad to raise your hand and join the queue. If you would like to withdraw your question, simply press star one again. And as a reminder, please limit yourself to one question and one follow-up. Your first question comes from the line of Scott Gruber with Citi. Please go ahead. Yes, good morning. Morning, Scott. Morning, Andy. I appreciate all the color on the dynamics at play in the frac market today. How do you see the U.S., you know, frac supply-demand balance today, you know, given the enlargement of the average fleet? It's grown a long way here the last couple of years. And do you have a sense of, you know, roughly, fleet utilization for the market? And can attrition alone drive us back to a relatively tight market balance in the not-too-distant future? Yeah. You know, in terms of fleet activity, it's really an interesting situation. We've been trying to explain, you know, for a while now, the dynamics in the data that you're getting from various public sources. You know, if you look at what we did across 2025 last year, you know, public data is showing a reduction in our fleet count, but at the same time, the size of our fleets, the amount of horsepower on location, has just been continuing to grow. You know, we're doing more Simul-Frac, we're doing more trimul-frac, and even on the same Simul-Frac, we're getting requests for higher rates and higher pressures. So that's causing us to put more equipment on location. When we do put more equipment on location, we certainly factor that into the pricing for the job. I mean, we're, you know, we're committing more assets, so, you know, it costs the operator more, but they're getting a cost benefit. You know, they've done their economic evaluation on, you know, what it takes to maximize production out of their wellbore, and that's what they've determined. So, you know, in some ways, it's been a win-win, but, you know, the challenge, you know, for people trying to understand the business is that while the fleet count looks like it's going down, we've actually remained really relatively steady in the amount of horsepower that's been deployed. So we've been, you know, we've been moving, you know, horsepower around to different places and growing the amount that we have on the well site. And, you know, I see that trend continuing, you know, at maybe a measured pace in 2026, but you see that trend continuing. What that means is it continues to reduce overall supply in the frac market. You know, all the equipment that we have that can burn natural gas is certainly out working, and that has a cost benefit to operators when they can burn natural gas. That market still remains very tight because of the amount of horsepower growth on a per-fleet basis. I appreciate all that. And then I, I think your, your Current Power business is looking at some opportunities to supply energy storage systems at, at data centers and, you know, other applications outside of, oil and gas. Can you provide some color on that initiative? Yeah, you know, we do have an electrical engineering division that's called Current Power, and they, they've, you know, build and engineer very specific microgrids, and they do battery storage for, you know, mainly our drilling rigs. You know, there may be an opportunity in the future for them to do some, you know, measured type of storage for data centers, but, you know, that would be a pretty large-scale project, even for us. There's some technology there that could be interesting, but I'd say it's very early to see if that pans out to anything. Okay. We'll watch. Appreciate the color. Thanks. Your next question comes from the line of Saurabh Pant with Bank of America. Please go ahead. Hi, good morning, Andy and Andy. Morning, Saurabh. Andy, maybe I just start with a bigger picture question. I think you were talking about increasing differentiation in your prepared remarks, and honestly, I see that in the Kimberlite data as well, right? I think, your performance, your value proposition seems to be improving in the eyes of the customers in both drilling and completion. As I think about, what it means for financial, right, it seems to me like, the gap between the top two, three, call it four players, including yourself and the other small medium-sized providers, is actually increasing, right? So it should be good for your pricing, power, in the market. So maybe just talk to that dynamic a little bit, differentiation and pricing power, and how pricing has held up a lot better. Yeah, appreciate that question, and thanks for noticing, you know, some third-party data that shows that we continue to improve our operations. Really pleased with, you know, how the teams have improved execution over the years. And also, you know, it gives us confidence to continue to fund them with capital for new technology. And we do think that that continues to differentiate us in the market, you know, both on drilling services and completion services. So, you know, really pleased with the performance overall for the teams. You know, we're working for some of the biggest E&Ps, you know, in the U.S., in both drilling and completions, and it's, you know, the size and scale of the operations, it's the breadth of services that we can provide, the level of technology we can provide, and the execution that we're providing in the field that's really driving all that. So it's not just one thing in particular, but it's multiple factors, and just really pleased with how that's been working out. I, you know, in terms of pricing, you know, one of the things that we've shown here over the last couple of years is even though you've seen, especially in drilling, a decline in the rig count, you haven't seen compression in margins like you've seen in previous years. Technology is a big part of that driver, where we can differentiate, certainly from much smaller companies, and it, you know, helps to, to, you know, really kind of shore up, you know, our ability to, you know, protect the pricing and margins where we can. You know, our business is certainly still competitive in nature, especially in West Texas, where you're seeing, you know, a little bit more slowdown in the oil markets versus the gas market. So there's still competitive market out there, but really pleased with how we're performing in general, and also very pleased at how well we've been able to, you know, keep the margins up relative to previous cycles. No, that's fantastic, Andy. Thank you. And then, maybe just a quick follow-up on what Scott was asking on the supply-demand side of things. I know it's very early to ask him about pricing power coming back to the market, but I know it will at some point, right? So in some ways, Andy, how should we think about how much incremental demand, maybe on the rig side and on the frac side, would it take for some pricing power to come back to the industry? Now, I don't know when it happens, but just some sense of what kind of demand pull we might need for that. Yeah, it's a really interesting situation, especially for us, where all of our equipment that can burn natural gas is out working today. And so, you know, if we see the activity increase in the natural gas basins towards the end of this year to supply, you know, both LNG demand initially and over time, you know, increasing power demand in the U.S., you know, that draw on natural gas is gonna cause an increase in activity in both drilling and completion. And on the completion side, we are essentially sold out of all of our equipment that can burn natural gas. When you're working in those gas markets, you know, the operators, the E&Ps, certainly wanna fuel that equipment with natural gas, and we would have to add to our, you know, asset base at that point, and that's gonna cause a significant inflection of pricing in that point. My expectation is that, you know, once we see an activity increase in these gas basins, it's really gonna drive an increase in the pricing on the completions as well, because we're gonna have to add assets to do that. Right. Right. Now, I think things move pretty quickly on both sides, right? So we should not forget that. A very quick follow-up for Andy, Andy Smith, if you don't mind. Andy, you were talking about some weather impact on your first quarter guidance. Did you quantify the impact, if I missed that, if you have any color on how big that impact is? We didn't quantify it, but it's in the range of $5 million-$10 million. It's included in our guidance, so- Okay ... it's certainly not incremental to anything. It's already included, but it's probably in the $5 million-$10 million range. Okay. I got it. Okay, Andy, thank you. Thanks a lot. I'll turn it back. Thanks, Saurabh. Your next question comes from the line of Jim Rollyson with Raymond James. Please go ahead. Hey, good morning, guys. Good morning, Jim. Andy, you kind of talked about the demand side with your technology and all the things you've been doing through this kind of market over the last couple of years. You know, one of the things that's really been pretty notable here over the last, at least the back half of 25, if not longer, is what you guys have been doing on the cost side. It showed up, you know, really in completion services kind of first. It certainly showed up in drilling services this quarter. Maybe just spend a minute on kind of, you know, what all you're doing to bring your cost structure down and kind of what inning you might be in, just as we think about, you know, and maybe a stable market, not that that happens, but, you know, how margins proceed in both those businesses going forward. Yeah. So, you know, my hat's off to the teams. They've really been digging in hard as to, you know, how we're spending every dollar out there, both in OpEx and CapEx. And, you know, you look at things like maintenance CapEx, you know, what are we spending our money on? You know, are there things that we can do to refurb versus buy new parts? Are there things that we can do to negotiate with some of our suppliers, given the state of the market? There's just a number of efforts out there to try to rein that in. I'll also say that the teams have worked to become more efficient, so they can do more with the same amount of people and get more accomplished from a maintenance standpoint. Maintenance has been a big driver in the cost savings in both, you know, the drilling services and completion services segments, both OpEx and CapEx. Yeah, Jim, I would add to that. So yeah, as Andy said, you know, you know, crew sizes, particularly around in the completion services area, as well as the support structure footprint. As we have consolidated these businesses over time, you know, we've looked to co-locate where we can or slim down sort of our fixed asset footprint in terms of our support facilities. And then on the SG&A side, as we've gone through and tried to integrate the back office even more, consolidate, centralize, it allows us to control some of those costs, get them out of the businesses, and let them be managed, quite honestly, from the corporate side. So we turn the business units loose to sort of focus on their operations more so than kind of what they're doing on the back office side. So I would say all of those things have an effect, and we'll continue to do more on those. But yeah, it's been a real focused effort over the last year or two. Yeah. Well, it's been impressive. And then just as a follow-up, you know, you kind of took upon this, this path of returning at least half your free cash flow, a couple of years or so back, and you've obviously exceeded that number pretty handily each year. You just raised the dividend by 25%, and, you know, I presume with all the things going on, your free cash flow conversion rate should probably be pretty, pretty stable, at least. Just curious, you didn't buy a whole lot of stock back in 4Q, and even with the dividend hike, and kinda where numbers are, you, you have quite a bit of room to be able to buy back stock throughout 2026. Just maybe your philosophy on that, given that, you know, your share price hasn't ripped, but it's, it's certainly improved a little bit from, from where it was at the bottom. I'm just kinda curious the philosophy there. Yeah, I would say, this is Andy Smith. I would say that nothing has really changed philosophically for us, Jim. You know, look, it's pretty clear for those that have been following us for a while, that we run this company to maximize free cash flow. And so as we look at anything on the capital allocation front, that's kind of our primary focus, whether it's, you know, looking at, you know, investing, reinvesting into our fleet, whether it's looking at buying back shares, or whether it's looking at M&A, we kind of look at them all in terms of how much cash flow per share accretion can we get out of those opportunities. And I would say in the fourth quarter, the reason there was a little bit of pause on the buyback was more about lumpiness of working capital and things like that, and it kinda came in late in the quarter, and so nothing really has changed. But we continue to look at all of our capital allocation priorities through that sort of free cash flow per share metric. And, you know, we ultimately think that in the end that serves us pretty well, and that's how we run the business. So again, I wouldn't say to read too much into that. I don't think anything has really changed in terms of our philosophy. Yeah, I agree. I don't think anything's changed in how we look at that. But one thing, you know, when you look at, you know, the bigger macro, and you look at what's happened in the industry over the last couple years, and, you know, the market softened over the last couple of years, but yet we're still generating strong free cash flow. You know, that's our focus, and so, we, you know, that gave us the confidence to go ahead and just raise the dividend. Because here we are in a softer portion of the market, but yet we're still producing strong free cash flow, and we still have forward visibility on that. Absolutely. Makes perfect sense. Appreciate the answer. Thanks, Jim. Your next question comes from the line of Derek Podhaizer with Piper Sandler. Please go ahead. Hey, good morning, all. I know you mentioned some of the comments around Argentina and sending some of your idle, idle rigs down there. Maybe just give us a sense of you walk around the world, we're seeing all this unconventional development pick up. Thinking specifically about your Turnwell JV over in the UAE. What can we think about you guys exploring these international regions, you know, starting with Argentina, maybe UAE, anywhere else? Just some comments and thoughts around that. Yeah, you know, we've looked at these markets for, you know, more than a decade to try to see, you know, where we can fit in and where it makes sense and, you know, where we can get, you know, decent earnings out of it. And, you know, these markets have, you know, various competitors, but they also have rig specifications that differ from the U.S. in a lot of markets. The interesting thing about Argentina, it's almost an identical rig specification to what we have here in the U.S. And so it's easy from a, you know, technology transfer and even a capital efficiency standpoint to say, "Okay, yeah, we can move a drilling rig down in Argentina and work in that environment without big technical changes." And so, you know, as the Vaca Muerta activity, you know, continues to grow in activity, and they continue to use the available supply in Argentina, they're looking to the U.S. to bring rigs down from various drilling contractors. This agreement worked out for us to, you know, partner up with a local supplier and who has a good reputation in the region and is working for, you know, some of the biggest E&Ps there. And so, you know, this worked out really well for us to be able to get to an agreement with them to provide them with a couple drilling rigs, to go down there. And, you know, while it's only two rigs leaving the U.S. market, you know, I think everybody who's been following Argentina knows that you've got operators that are there currently. You've got U.S. operators that are looking to move into Argentina, and activity will continue to grow in, in Argentina over the next five years. And those rigs are gonna come out of the U.S., and over time, that's gonna reduce the U.S. rig supply. And so, you know, we'll continue discussions with companies that are currently there and companies that are going down there, and we'll provide rigs where it makes sense for us to provide rigs. Got it. That makes sense. Very helpful color. And then, just thinking about the frac side of things, you know, appreciate the comments, quantifying some of the impact here in the first quarter, due to winter, but maybe you can take a chance on walking through second quarter, third quarter, what you see out there, your customer conversations, you know, will we get a snapback in utilization? Just trying to think through the different crosswinds around pricing resetting. Just maybe some help understanding as we move through the year, what we could see out of the completion, side of the business. Yeah, you know, we were really pleased to see that the first quarter was still relatively steady. You know, the fourth quarter, we were able to exceed expectations in overall activity, you know, relative to how a fourth quarter normally plays out. And then relatively steady, you know, into the first quarter, you know, the weather issues aside that everybody went through. You know, as we go through the year, if the commodity prices stay in this $60 range, you know, my expectation is that the oil market stay relatively steady. I think that, you know, as a lot of E&Ps were working on their budgets in December, you had, you know, oil commodity prices at various levels in December. which kind of made it challenging for a number of our customers to decide what their activity is gonna be during the year. But we've seen more resilience, I think, than many of us have expected. And if that resilience persists and oil stays in that, you know, upper $50-$60 range, then the market will likely to remain relatively steady. Great. Thanks, Andy. I'll turn it back. Your next question comes from the line of Stephen Gengaro with Stifel. Please go ahead. Thanks. Good morning, everybody. I guess, on the, on the frac side, I was just curious what your view is on two things. One is, if you think we'll see further consolidation in the business, and maybe tied to that, do you feel like over the last, I don't know, six months or a year, that the behavior of the, of the industry and the peers has been fairly good, or do you still see some people who are underpricing the market? So I think the frac market has been evolving from a technology standpoint. And I think that you're seeing differentiation with the top three or four players versus others. And I think that technology differentiation continues, you know, for the next few years. You know, and you can certainly see it in where we're investing dollars. So we continue to invest in the 100% natural gas Emerald fleets that we have deployed. There's still very strong demand for equipment that can burn in 100% natural gas, and we're gonna continue to do that. And so we're gonna continue to grow our capacity of that high-end frac equipment, probably higher than some of the others are deploying today. So we see that. And then you see Digital. Digital still has a lot of evolution to go in the frac space. And so, you know, we announced, it was a big event at, an industry conference this week in the Houston area, where our teams rolled out the new eos platform for Digital. It allows, you know, our customers to be able to aggregate all their data without various third parties, put it all in one place, visualize it, work with it, do what they need to do with it. But that platform is not just about data aggregation and moving data, it's also about the controls and working with the control systems that we have, which are proprietary to our equipment. And, you know, we have the Vertex automation on the frac. And so it's these kind of investments in the higher-end technology on the equipment side, but also the investments on the Digital, which will allow us to continue to differentiate. I think that, you know, it's gonna roll up to the top four, maybe just three players that can do that and differentiate from the others. Okay. Thank you. That's, that's helpful. And just the other quick question, just on the rig side, on the North American market, do you feel like pricing has, has stabilized? You know, I think, where we are today, you've got some available rigs in West Texas. You know, it's still a price competitive environment out there, but I'm pleased with our ability to, you know, protect our pricing and margins the way we have. You know, we'll just have to see how it plays out. I think, you know, where the commodity price, you know, lands as an average for the year will be a lot that drives that. So if it stays upper $50s-$60s, then, you know, I think pricing remains relatively stable. It'll get a little bit more competitive if we see a different commodity price that's lower. But I think, you know, where we are now, that it stays relatively stable. Okay, great. Thanks for your help. Thank you. And your next question comes from the line of Arun Jayaram with JP Morgan. Please go ahead. Yeah, good morning, gentlemen. I was wondering if we could start with the CapEx. You mentioned how you're reducing CapEx by around 15%, to less than $500 million. I was wondering if you could maybe unpack the year-over-year declines, what that kinda represents, maybe a little bit of a mix between drilling and completions, and perhaps, you know, how much of the CapEx is going to be earmarked for the Emerald direct drive kind of horsepower? Yeah, so I can give you a little bit of color on that. So of our total CapEx, projection or for CapEx guidance, about 40% of it is going to drilling, about 45% of it is going to completion services, a little over 10 is going to drilling products, and the rest is sort of corporate and other, on a percentage basis. And in completions, of that 45%, about gross dollars, about $65 million or so is going to new Emerald equipment, that'll be coming into the fleet over the course of the year. That's super helpful. Andy, for you, I wondered if you could maybe elaborate on this trend you're seeing with continuous pumping. You know, I think in one of your previous slides, I've seen that you've talked about how Simul-Frac now is representing about 30% of frac activity today. Where are we in terms of continuous pumping? And is it advantageous for operators such as Patterson with the to pursue continuous pumping? Just, you know, obviously, I assume you're getting paid for the extra horsepower, you know, on site. ...Yeah, continuous pumping is interesting in that, you know, there are certain advantages for the E&P to-- if they don't have to stop, you know, you're basically pulling production forward. So there's a value to the E&P to do that. And the E&P has to, to work through those economics to decide what that value is. Because on average, if we're pumping, you know, 22 hours per day across all of our fleets, and you want to take that number from 22 to 24, we may have to deploy, you know, in terms of capital, another 20%-30% of capital on location with more frac pumps, more, you know, high-pressure iron, more valves, to be able to have a system out there that can achieve that. And so the E&Ps-- and we, we charge for all that equipment when it goes on location. So the E&Ps have to do their own, you know, earnings math to decide, you know, is that worth the extra equipment that's on location to be able to accomplish that? You know, is that value of bringing production forward, you know, on that particular pad or multiple pads, really worth that effort? So what we see today is we see a number of E&Ps that are trialing it to see how it works, to see what the costs are gonna be. And we're working with, you know, a number of our customers to reduce those costs, so we don't maybe have to put so much equipment on it on there. So it's all evolving at the same time. But, at the end of the day, it's gonna be up to the E&P to decide, does it make economic sense for them? Technically, we can do it. Technically, we know how to do it. We're working to continue to reduce the cost to do it, but it's the E&P's economic decision at the end of the day. Yeah, Andy, you said it's 20%-30% more horsepower at the well site to do that? I, I would say 20%-30% more capital in general, because you've got pump equipment, you've got, maybe redundancy on a number of things, you've got more piping, more valves out there. Because, you know, if you're gonna pump for multiple days straight, you still need to be able to access pumps to maintain them. So you have to have- Yep ... you know, more pumps than you're using so that you can swap pumps in and out of the lines while you're circulating without stopping the circulation. So you're gonna have more equipment on location so you can manage all that. Okay. If I could just sneak in one more, Andy, though, I believe you were anticipating running around 2 million horsepower ± in, you know, 1Q or currently. What is your average fleet size in terms of horsepower today? You know, there's no average fleet size. I mean, I can tell you every fleet that we have deployed is a different size. You know, is it in the Midland Basin? Is it in the Delaware Basin? Is it a Simul-Frac in the Delaware Basin? Is it pumping in the Haynesville? And so every one is different. Every one has become very bespoke to whatever you know operation the operator is trying to accomplish. You know, as I mentioned earlier, just you know, even a Simul-frac job, we might have a Simul-frac job today that's got another 20% of horsepower versus a Simul-Frac last year, because they want to do it at higher rates and higher pressures because they're seeing increases in production. So, you know, and it even changes from pad to pad. It may be a high amount of horsepower on one pad, and for the same customer, it moves and it shrinks for the next pad. So it's, it's constantly changing. Great. Nice results, Andy. We'll talk soon. Thanks. Thanks. Your next question comes from the line of Ati Modak with Goldman Sachs. Please go ahead. Hey, good morning, team. Andy, I was wondering if you could give us color on the private versus public customer conversations as we think about your exposure in the U.S.? Hey, Ati, good morning. So, you know, we work for some of the biggest publics, and we also work for some of the biggest privates in the U.S.. And I would say that the large privates, you know, think of things long term, just like the large publics think of things long term. You know, they take a multi-year view to everything, and, you know, that's how they view it. We do some work for some of the small private equity-backed privates, but that's a very small percentage of what we do. We're heavily weighted to, you know, the largest E&Ps in the US, whether they're both public or private. Got it. And the Saudi opportunity, it sounded like it's mostly on the bit side because of in-country value. Is that the right way to think about it, or are there other strategic opportunities for you down the road? The Saudi, for now, is focused on drill bits for us, and you're absolutely right. It's the in-country value equation that the country uses. And so if you manufacture in country, you know, it improves your score, it allows your customers to buy more products from you. If you're manufacturing in country and exporting out to other countries in the region, that improves your score and allows your customer there to buy more from you. So we think that that's, you know, certainly a benefit for us, and our team's done a great job of getting us to the point where we can manufacture the first one in December, and we'll continue from here. Thank you. Your next question comes from the line of Keith Mackey with RBC Capital Markets. Please go ahead. Hey, good morning. Good morning to you. Morning. Just wanted to start out on, on the rig side. Can you just talk through some of the technology offerings on your rigs? How has that changed, and what sort of revenue or just net benefit uplift do you get from, from the technology in this market? And finally, to that, more of your customers are starting to talk about robotics on the rig floor. What's your view there? ...So, you know, our Cortex automation is, you know, a number of applications that enhance our control systems and automate a number of the functions that a driller might normally do when he's operating the drilling rig and working with his crew. And we've developed a number of these applications over the years, and it's been an interesting evolution because as you start to develop applications, then, you know, your customer comes back with what ifs. Well, what if we do this, or what if we do that?" And that either improves the existing applications, you know, where you tweak them some more, where our data analytics team will, you know, look at the data in different ways and decide how to best fine-tune these applications, or the customer works with you to come up with a new application that they see as beneficial and, you know, ask for priority on that. And so, you know, over the years, we've continued to develop those out, and it's, you know, there's revenue involved. We certainly charge for these, but, you know, it also means that we, you know, become more important for that customer when we're offering these things. And we tune these applications to their specific procedures or their workflows or their spec, you know, specifications on how they wanna see the drill bit go back to bottom, or what kind of weight on bits or, you know, they want to carry on the drill bit, or, or what kind of differential pressures they want to maintain. And so, you know, it just allows us to, you know, be closer with the customers on how we run those types of operations. In terms of robotics, our teams have certainly, they're looking at it. There are some advantages. There are also some big costs, and we've done a lot of the groundwork to deploy that on either our APEX XC + rig or our APEX XK. You know, I think over time, we'll, we'll do that as well, depending on what the customers are requesting. Got it. Thanks for the color. And just, just finally, you know, Q4, we were expecting a lot more seasonality from, you know, you and several of your peers. Can you just give us a little bit more color on, on really why you think that didn't happen and, and things were a lot more resilient? You know, is there some element of the E&Ps just not being able to slow down, given where current activity levels are, or there are pricing incentives given to keep, keep fleets going? Just what is, what is your sense of really why activity was so resilient in Q4? I think for us, it was a combination of two main things. It was our customer base. We, you know, as I've mentioned before, we work for some of the largest customers, you know, in the U.S., and those customers have stayed, you know, even more resilient than we've thought and just kinda kept working through the quarter, maybe more than they normally would. And then the other piece is for some of those customers that may have slowed down, our teams have done a real good job, you know, placing that equipment in other places to be able to do that. Certainly wasn't, you know, pricing concessions, but really more working with the customers. But again, I think it goes back to our customer base and the ability of our teams, you know, to know all the customers so that when we do have to move something around, that we can do that efficiently. Got it. Thanks very much. Thanks. Your next question comes from the line of Eddie Kim with Barclays. Please go ahead. Hey, good morning. Just wanted to dig into the completion services guide for the first quarter. You said you expected gross profit around $95 million, which represents about a 14% sequential decline. At the same time, you said you expected activity to decline only slightly in the first quarter due to winter weather. So, I mean, that would seem to imply a not insignificant pricing decline from fourth quarter first quarter. Is that a fair assessment? And should we expect that to be sort of a headwind for you as your fleets move on to this lower pricing level as we move throughout the year? No, not at all. I wouldn't say this is any significant pricing decline by any means. I think this is all more activity related. You know, you can go back and look at the number of days below freezing in the Permian or the number of days that Pennsylvania had heavy snowfall, and that's where we were, you know, held up in activity in the first quarter. So that's just pushing, you know, revenue from the first quarter, eventually, you know, into the second quarter. So, you know, that's how that's kind of moving. In terms of pricing decline, you know, what we've said before, even at the last earnings call, we're gonna have a slight decline because of various tenders that have happened, you know, in the second half of last year, but that's in the single digits. It's, you know, any price decline on average is single digits, but certainly, that's not what's driving, you know, what you're seeing in the decrease in gross profit. It's more had to do with weather activity and some mix in activity during the quarter. Got it. Got it. Okay. Thanks for clarifying my understanding there. That's okay. A follow-up is just, you opened up a new manufacturing facility in Saudi. You said you're manufacturing drill bits in the country. Could you sort of talk about the growth ramp-up you expect in Saudi, maybe this year and next? And do you think Saudi demand is gonna be sufficient to absorb all that capacity coming out of that new facility, or is there gonna be opportunity to sell drill bits into other countries in that region in a couple of years? Yeah, you know, we've seen, you know, of course, we follow the rig count and the announcements on increasing rig count in Saudi because that's what drives our drill bit business. You know, they've had a big slowdown over the last year and a half in both onshore and jack-up drilling rigs over in Saudi, and we're seeing the calls to put the onshore drilling rigs back to work. And so you've had a number of drilling contractors that operate in Saudi that have made those announcements... and, you know, that will start to drive an increase in drilling, drill bit demand. We do expect, you know, the customer over there to consume some of their existing drill bits that they might have in a warehouse. But as they, you know, go through that, then, you know, they'll be calling for new drill bits, and, you know, we'll have some manufacturing capacity over there to be able to meet that need. We'll probably still likely ship drill bits from the U.S. at the same time, so it'll be a mix of local manufacturing plus drill bits coming into the U.S. until we expand our manufacturing over there. But, real pleased with, you know, what the team did, given some of the constraints and challenges we had over there to get manufacturing set up. We've been doing remanufacturing in Saudi for years, so it was really a matter of expanding, you know, the space, the types of machines that we needed over there, and also the skills that we needed over there to be able to go to full manufacturing. But, they were able to produce that first drill bit in December. Got it. Great. Thanks for that color. I'll turn it back. Thanks. And we'll take our last question from Jeff Bellman with Daniel Energy Partners. Please go ahead. Hi, good morning, everybody. Andy, a bit of a high-level question and definitely related to some of what you've already addressed, but I wanted to get your take. If I had a thesis that the U.S. industry's gone a long way working through their Tier 1 inventory, and activity is gonna have to increasingly shift towards, let's say, more complex or Tier 2 resources, how do you view that transition for Patterson? And how does your asset base help them, help operators kind of extend their economic life and expand their resource base if that shift actually has to occur? Thanks. Sure. You know, there's a lot of talk about shifting from Tier 1 to Tier 2, and I really think that's operator-specific. You know, we work for some E&Ps that tell us they have another decade of Tier 1 that they're still working on, and then we have some E&Ps that say, "Yeah, we're gonna start to look at some of the Tier 2 or some of the deeper geological horizons." For us to do that, that means more service intensity, and more intensity means that, you know, it's positive for our pricing. But on the drilling side, it means we may need to, you know, continue to add capacity on the size of the rig that we're using, so we'll continue to do that. And on the completion side, it, you know, may require more horsepower and location for some of these deeper plays. And so it just increases overall service intensity, which is positive for us. Great. Thank you. Thanks. That concludes our question and answer session. I would like to hand it back to Andy, Andy Hendricks, for closing remarks. Thank you. I appreciate everybody dialing in today, and we'll wrap up this call for the Q4 2025, and look forward to talking to you again in April. Thank you. Thank you, presenters, and this concludes today's conference call. Thank you all for joining me. Now disconnect.