Hello, everyone. Thank you for joining us and welcome to Patterson UTI's second quarter 2026 earnings conference call. After today's prepared remarks, we will host a question and answer session. If you would like to ask a question, please press star one to raise your hand. To withdraw your question, press star one again. I will now hand the conference over to mike sabella vice president of investor relations please go ahead takes no obligation to publicly

update or revise any forward-looking statements statements made in this conference call include non-gap financial measures the required reconciliations to gas financial measures are included on our website at patenergy.com and in the companies prior to andy hendricks thank you mike and welcome to our second quarter earnings conference call The first half of the year was a clear reminder of how quickly the global energy landscape can change.

It also reinforced why secure, reliable oil supply matters, particularly with geopolitical uncertainty still. That backdrop is likely to remain part of the market for some time, and it highlights the important role U.S. oil and natural gas production plays in supporting energy security, both domestically and abroad. U.S. shale remains one of the world's most innovative and resilient energy markets. As the industry evolves, we are seeing a clear separation between service companies that are investing in oilfield technology, performance and execution, and those that are not. Operators are placing a premium on efficiency and reliability, and value is increasingly being created by a smaller group of oilfield service companies with the scale, technology, and capability to meet those expectations this differentiation is offering us opportunities to invest capital into assets that support premium pricing and returns we see this dynamic playing out across both drilling and completions for customers those capabilities make it easier to economically develop more complex resources and extract more value from their assets for patterson uti our technology leadership is a competitive advantage and creates a longer runway of high return opportunities for us. Second quarter, each of our businesses demonstrated growth and performed ahead of expectations, including compared to the improved guidance we provided in our mid-quarter update. That momentum carried into the third quarter. These results reflect the value created from targeted investments we have made to strengthen our technology leadership across core markets and prepare Patterson-UTI for the next phase of U.S. shale development. Importantly, we achieve these results before any benefit from the additional growth capital announced during the quarter. Those investments are now underway, and we expect them to support further profitability growth into 2027 and beyond, while further extending our competitive advantage across the industry. Momentum strengthened as the quarter progressed. We entered the quarter cautiously optimistic that activity and pricing were beginning to improve, but both the pace and the magnitude of that improvement exceeded our expectations. As customers gained confidence in the commodity outlook and began increasing activity, our scale, fleet quality, and operational capability allowed us to capture upside across our businesses. Just as importantly, our team secured better pricing in each segment. Customer requirements are becoming more demanding as shale development grows more complex. Operators are increasingly seeking drilling rigs with larger structures capable of handling deeper zones and longer laterals, completion equipment that can be powered by natural gas, and more advanced digital and automation capabilities. At the same time, the supply of the most capable equipment remains constrained, and we believe our asset base and technical expertise are among the best in the industry. As U.S. shale moves into its next phase, Patterson UTI has the scale, fleet quality, and technology platform to extend its competitive advantage and deliver attractive returns for our investors. From a macro perspective, the outlook has become more constructive, even with the commodity price volatility we've seen over the past couple of months. While prices have since pulled back from recent highs, they remain well above the levels many customers assumed in their initial 2026 budgets. The current strip supports a higher pace of U.S. shale drilling and completion activity than we are seeing today. The oil strip, around $70 per barrel through the end of 2027, our outlook remains constructive, especially given that much of the industry planned for 2026 using assumptions of $60 per barrel. Even as the U.S. rig count has increased over the past several months, public EMPs have generally kept activity close to the levels that they planned before oil prices moved higher. That discipline among larger public operators has been one of the defining features of U.S. shale in recent years and has helped reduce earnings volatility for our sector compared with prior cycles. At the same time, the stronger commodity backdrop has underscored the important role private operators are playing in the market. Private EMPs have responded more quickly to higher oil prices and are now driving a meaningful increase in drilling activity still our discussions with the public emps about higher activity levels are gaining momentum and are increasingly concentrated around our highest specification rigs and most advanced completion equipment large public customers are planning several years ahead in prioritizing rigs with greater hook load and pipe wracking capacity to drill deeper wells and longer laterals, along with hydraulic fracturing equipment that can be powered by natural gas. These requirements are becoming more important as shale development grows more complex, and the equipment capable of meeting them remains in very short supply across the industry. This should create opportunities for us to drive growth into 2027 and earn strong returns as the industry moves forward. Oil-directed activity to improve further into 2027. Private EMPs are leading the initial recovery, but the next phase of growth should be supported by increasing demand from public customers. Importantly, that demand is expected to be concentrated around higher specification equipment that can improve efficiency, reduce operating risk, and deliver better returns for both our customers and investors. Big activity recovered faster than we expected during the quarter. Pricing on new contracts increased by approximately 10 to 15 percent versus first quarter levels. And upgraded rigs are being deployed at day rates several thousand dollars per day above standard superspec rigs. Across most regions outside the Permian, high-quality rigs are effectively sold out, with little to no idle equipment available for reactivation. While rigs can be mobilized between basins, the cost of mobilizing incremental capacity should support pricing momentum for rigs already working in those basins, even if the overall rig count holds near current levels. In the Permian, demand is increasing, and customers are reluctant to lose active proven rigs and crews, given the startup costs and re-crewing needs associated with reactivating cold-stacked equipment. That dynamic is also supporting additional pricing improvement in the Permian. As EMPs plan their drilling programs for the next several years, they are increasingly looking for rigs capable of drilling deeper wells and longer laterals more efficiently. That means larger structures, higher hook load capacity, greater pipe racking capability, expanded circulating systems, and more advanced digital and automation features. These upgrades require capital and expertise, but the returns are very attractive. and are typically supported by firm take-or-pay contracts or long-term customer agreements that allow us to recover the investment when the within the initial term of the agreement the direction of the market is clear roughly half of recent wells drilled have laterals longer than two miles compared with about one-third last year and four mile plus laterals now represent more than 10 percent of recent wells roughly four times last year's average We are also seeing a meaningful increase in wells targeting deeper shale intervals, with that activity more than doubling from last year. For larger EMPs, these trends reflect where U.S. shale development is headed, and we are moving decisively to capture this work through high-return rig upgrades and differentiated execution. As demand for upgraded rigs accelerated during the first half of the year, our technology and engineering teams move quickly to offer capital-efficient solutions to our customers by upgrading our existing high-quality fleet to fit these new specifications. In completion services, we saw a meaningful sequential improvement in the second quarter. Pricing discussions were more favorable than we expected at the start of the period, and frack calendars remained largely full throughout the quarter. Our teams also stayed focused on aligning our capacity with the most efficient customers in the industry, which enhances fleet performance. Completion demand improved from the first-quarter levels as customers began working through a relatively modest inventory of drilled and uncompleted wells. Even that modest increase highlighted how tight the market remains for capable frack Natural gas-powered capacity is effectively fully utilized across the industry, and the horsepower still available in the market is largely older, less efficient, and more expensive to operate diesel equipment that many customers prefer not to use. As we look to the second half of the year, completion demand tied to the roughly 50 rigs added across the industry since this spring has not yet fully shown up in the market. The additional drilling activity will require incremental frack fleets during the second half and support growth into 2027. With capable equipment already highly utilized, incremental demand should support further pricing momentum. Our strategy and completions have been focused on improving the quality of our fleet, not adding horsepower. We are systematically retiring older diesel equipment and replacing it with more capable gas-powered assets that are better aligned with customer demand and the direction of At the beginning of the year, we expected our available frack horsepower to decline as diesel retirements outpace the addition of new technology. The capital increase we announced in May allows us to add more direct-derived, 100% natural gas-powered emerald frack assets. As a result, we now expect our available horsepower in the second half to remain broadly in line with the first half. The objective remains growth in earnings and returns. By shifting more of the fleet toward gas-powered equipment, we are increasing the share of assets that customers value most and are commanding better pricing and margins. By year-end, we expect about 90% of our active horsepower to be powered by substantially by now. That mix enhances what we believe is already one of the highest quality fleets in the industry and should allow Patterson UTI to capture a larger share of customer demand. Taken together, improving demand, limited availability of capable equipment, and our strategic shift towards gas-powered assets supports an increasingly constructive pricing and margin environment as the year progresses. The product segment delivered an excellent quarter in a challenging operating environment, achieving its highest revenue since we acquired Elterra in 2023. The conflict in the Middle East created disruption across logistics, supply chain, and activity levels in several important markets, but our team stayed focused and managed effectively through those challenges while keeping employee safety at the fore. Even with those headwinds, along with the seasonal impact of spring breakup in Canada, both revenue and adjusted gross profit increased sequentially. We gained share across several markets and achieved a meaningful improvement in pricing from earlier this year. Internationally, the business built momentum despite conflict-related disruption in the Middle East, our largest international region. Drilling products delivered record international revenue in the quarter with sequential growth across our key geographies. That performance reinforces our view that international markets continue to provide attractive long-term growth opportunities for this. At the same time, our U.S. business remains a stead of foundation for this segment, representing roughly 70% of revenue. Our U.S. team has executed well at multiple points in the rig count cycle, consistently increasing the value we capture per active rig. In the second quarter, we neared another company record for revenue per industry rig. We were also encouraged by the progress in our downhole tools business, which is proving to be both highly innovative and complementary to our drill bit platform. Revenue from downhole tools has increased significantly since the end of 2025 and now represents approximately 5% of segment revenue. We see this product line as a natural extension of our drill bit offering and an attractive platform for long-term global growth. Geothermal also offers a small but quickly growing source of demand where bit runs have doubled compared with the end of 2025 and should grow further. These results reinforce our confidence in the long-term expansion opportunity within drilling products, as well as the segment's ability to generate attractive cash conversion. We remain focused on becoming the leading drill bit supplier in every market we serve by combining differentiated technology with consistent execution and deep customer relationships. As we begin the second half of the year, we feel very good about our role as a leading U.S. oil field services provider and the quality of our operations. We are working with the right customers, deploying the right assets, and delivering high-quality services and products across the markets we serve. That focus on strengthening the core of our business is central to creating long-term shareholder value, while also giving us the flexibility to pursue disciplined opportunities to expand our footprint and drive additional growth. While oil prices have moderated from the highs we saw earlier this year, the current strip remains supportive of higher demand for U.S. shale services and products over the next year. Both public and private customers are focused on maximizing value for their shareholders and that should translate into greater demand for Patterson UTI's differentiated capabilities. With the upgrades we are making across our drilling and completions fleet in 2026, we believe we can capture a larger share of the market and deliver attractive returns for our share. As the year has progressed, we've seen growth in long-term, high-return work. Many of the investments we are making in 2026 will not meaningfully contribute to results until late this year and into 2027, and working capital needs are increasing as activity accelerates. Even so, we still expect adjusted free cash flow this year to more than cover our 2026 dividend payments, and our capital allocation strategy remains unchanged. We are directing capital toward investments we believe will drive the highest long-term free cash flow per share for our investors. Those investments should support a meaningfully higher free cash flow year in 2027. I'll now turn it over to Andy Smith who reviewed the financial results for the quarter.

Thanks Andy. Total reported revenue for the quarter was $1,228,000,000, a 10% increase compared to the first quarter. We reported a net loss attributable to common shareholders of $20 million, or $0.05 per share. The net loss includes non-cash charges totaling $21 million related to the exit of our contract drilling business in Columbia, as well as $5 million in non-cash charges associated with the write-down of our minority interest in non-controlled entities. Adjusted EBITDA for the quarter totaled $232 million. dollars. Our weighted average share count was 380 million shares during Q2. Consistent with normal seasonality, working capital was a use of cash during the first half of the year, and the pace of the activity increase made that headwind more pronounced than in recent years. Those trends typically become more favorable in the second half, and even as activity builds, we expect working capital to be a source of cash during the second half. Even after the anticipated full-year working capital field and higher capital spending, we expect 2026 adjusted free cash flow to more than fund our dividend payments for the year. As we mentioned previously, we are exiting our contract drilling operations in Colombia. Our Colombian assets are aging, and changes in Colombia's political environment have reduced the commercial attractiveness of additional investment. Remaining competitive there would have required an incremental capital investment, and we believe that capital can be better allocated to higher return opportunities elsewhere in the business or return to shareholders. In drilling services, second quarter revenue was $374 million and adjusted gross profit was $114 million. Operating costs included roughly $20 million of non-cash charges related to the exit of our drilling operations in Columbia, primarily from the write-down of inventory that supported older rig technology and the write-down of other assets in the country. Excluding those non-cash charges, adjusted gross profit would have been $134 million. In U.S. contract drilling, we recorded 8,361 operating days during the quarter and averaged 92 operating rigs. Revenue per day improved from the first quarter, and our directional drilling business posted a meaningful sequential improvement in results. For the third quarter, we expect our drilling services rig count to average approximately 100 rigs, and we expect to exit a quarter above that level. For the segment, we expect adjusted gross profit to be approximately $145 million. In our completion services segment, second quarter revenue was $754 million, and adjusted gross profit was $123 million. Results reflect a largely full frack calendar and improved pricing across a portion of our fleet compared to the first quarter. As we moved through the second quarter, it became clear that utilization across the pressure pumping market was very high. Even a modest increase in demand was enough to support meaningful pricing improvement. Equipment that can run on natural gas appears to be nearly fully utilized, and given the significant cost savings natural gas provides compared to diesel, we expect demand for that equipment to remain strong. As we add more natural gas-powered completion equipment to our fleet later this year and phase out older diesel assets, we see upside to margins. For the third quarter, we expect completion services' adjusted gross profit to be approximately $140 million. That outlook is supported by near-full utilization of our active assets and additional pricing improvement compared to second quarter levels. In drilling products, second quarter revenue was $91 million and adjusted gross profit was $37 million. Even with conflict-related disruptions in parts of our Middle East business and the seasonal impact of spring breakup in Canada, the segment delivered a 14% increase in revenue and higher adjusted gross profit compared to the first quarter. The second quarter was the highest quarterly revenue for drilling products since we acquired Ulterra in 2023. For the third quarter, we expect drilling products, adjusted gross profit to be approximately $40 million. That improvement should be supported by the seasonal recovery from spring breakup in Canada and higher activity levels in the U.S. Other revenue was $9 million for the quarter, and adjusted gross profit was $7 million. Profitability improved sequentially, driven by higher oil prices, as our other operations consist entirely of our non-operated oil-weighted EMP interests. For the third quarter, we expect adjusted gross profit in other to be approximately $5 million. General and administrative expenses were $68 million in the second quarter. For the third quarter, we expect G&A expenses to be approximately $70 million. Depreciation, depletion, amortization, and impairment expense was $218 million in the second quarter, and we expect it to be approximately $225 million in the third quarter. During the second quarter, we invested $156 million in capital expenditures. That amount included $60 million in drilling services, $75 million in completion services, $19 million in drilling products, and $2 million in other and corporate. As we previously announced, we expect 2026 capital expenditures net of proceeds from asset sales to be approximately $600 million. In drilling services, our CapEx includes investments in additional rig upgrades, including larger structures, enhanced circulating systems, and expand digital and automation capabilities across more of our fleet. In completion services, the capital supports additional 100% natural gas powered emerald frac fleets, which should allow us to keep second half frac activity broadly in line with first half levels as we intend to retire older diesel assets in the second half of We ended the second quarter with $203 million of cash on hand and no borrowings outstanding under our $500 million revolving credit facility. During the second quarter, we refinanced our 2028 senior unsecured notes, extending that maturity to 2036. As a result, we have no senior note maturities until 2029, and we now expect interest expense to be approximately $20 million per quarter. Our board has approved a quarterly dividend of $0.10 per share, payable September 15th to shareholders of record as of September 1st. I'll now turn it back to Andy Hendricks for closing remarks.

Thank you, Andy. Andy, before we conclude the prepared remarks, I want to leave you with a couple of key points. The conflict in the Middle East is another reminder of the strategic importance of U.S. oil and natural gas production to national security and global energy stability. Geopolitical uncertainty will likely remain a part of the energy landscape, and a strong domestic energy industry remains one of the most effective ways to protect against global supply disruptions while supporting reliable energy access at home and around the world. At the same time, the U.S. shale oil field services market is increasingly being shaped by technology adoption and advanced digital and automation capabilities. Patterson UTI has invested across each of these areas, positioning us as a leader across our businesses and creating a strong value proposition for customers focused on performance, reliability, and capital efficiency. As Shale competes for capital globally, we believe our technology, fleet quality, and execution will help drive stronger outcomes for our customers and better long-term returns for our shareholders. As we invest for the future, our capital allocation priorities remain clear. We are directing capital toward growth opportunities that will strengthen the long-term free cash flow of the business and create the greatest value for our shareholders. Our 2026 capital program is focused on high-return investments that enhance our competitiveness, support stronger customer demand, and position Patterson UTI for improved performance in the years ahead. We expect free cash flow to improve in the second half of this year and improve meaningfully in 2027 and beyond. We want to thank all of our employees for their dedication to the company and look forward to delivering on the company's potential. We'd now like to open the line for Q&A.

We will now begin the question and answer session. Please limit yourself to one question and one follow-up. If you would like to ask a question, please press star one to raise your hand. To withdraw your question, press star one again. We ask that you pick up your handset when asking a question to allow for optimum sound quality. If you are muted locally, please remember to unmute your device. Please stand by while we compile the Q&A roster. Your first question comes from the line of Saurabh Pant with Bank of America. Your line is now open. Please go ahead.

Hi, good morning, Andy and Andy. Morning, Rob. problem uh andy uh it's it's really really heartening to see the the significant improvement in activity and pricing i think on the rig side you might have dropped in the high 80s you are now at 99 you expect to end the quarter at 100 plus practice pretty much sold out maybe just help us a little bit andy in terms of the amount of visibility you are getting as you reactivate these rigs and the fractions are busy right so how should we think about what kind of duration are you getting on these rigs as they're going to work? And I think I heard you say that your discussions with the public EMPs are gaining traction. So maybe help us think along those lines, private versus public customers, what you're hearing from them.

You know, being a drilling contractor, we get a lot of advanced conversations around what customer plans are in the U.S. And as everybody's seen in the data and we discussed this morning, it's certainly the private EMPs that are moving quicker than the publics. But, you know, when we reactivate a drilling rig, we'd never reactivate just for a few wells. It's always for a longer-term program. It's not worth the investment for us to do that for just a few wells. So every rig is getting reactivated. And rigs that are getting upgrades are signing long-term contracts, six months in general, but some even longer. And so as these rigs get deployed in the second half of this year and their contracts start, you've got rig contracts that are not just this year. You've got rig contracts that are also into 2027. So that's the kind of visibility we have today just with the privates that are moving quickly to deploy rigs. We're also in discussion today with public EMPs. They're making plans for later this year, for early next year, and discussing internally what they want to do. Some of those plans are, you know, firming up in the second half of this year, and you'll probably hear more about it from their own disclosures. So I don't want to call anything out in terms of specifics or areas because, you know, it's up to the public to make. But we're certainly in those discussions. And the interesting thing, of course, is ramping up as fast as it has, you know, the well counts ramping up and frack activity and completion activity will follow. And so that's why we're very encouraged about completion activity in the second half of this year and also going into 2027. And combine that with a shortage of high-end equipment.

No, that's very helpful, Andy. Thank you. And then my follow-up is more on the free cash flow side of things. Of course, the second quarter was way down by working capital, which is normal for this time of the cycle. Your activity ramps up, your working capital ramps up. But I think, Andy, you were talking about free cash flow improving significantly in 2027. I know it's a little early to talk about 27, but maybe give us some directional color on what to expect for 27, maybe on the capex side of things, and maybe how are you thinking about investing in some of the rigs, Andy, that you were talking about, bigger substructures, higher capacity circulation systems. How much are you spending potentially on those rigs? How are you thinking about returns? So just some color on where we should expect free cash flow to go next year.

Yeah. Hey, if you don't mind, Sir Rob, what I'd like to do is maybe give a little bit more color on pre-cash flow during the quarter. And then, you know, Andy and I can talk about investments going forward. But if you look at our pre-cash flow in the second quarter, and we've talked about this in the past, seasonality, we always sort of have a seasonally low quarter in the second quarter. And the first reason for that is because, you know, we have some prepayments that come in at the end of every year, which generally pay for work to be done in the first and the beginning of the second quarter of the year, ultimately that delays sort of you then ramping up your cash flow for those customers until later in that year. So you have this weird sort of chunky cash flow at the end of each calendar year that then sort of amortizes off over the first and second quarters of the years, and it looks like lower cash flow. I'm always happy to take payment earlier from any customer that wants to pay earlier. So if there's any listening, this isn't a problem. The second thing I would say is that, look, activity ramped up. You mentioned it. That's a headwind. As activity ramped up through the second quarter, you know, we get those billings out, and they end up sitting in receivable this end of the quarter. That's the use of cash. And then finally, the third thing that I would point out, and we've talked about this in the past as well, after the merger with NextYear and the acquisition of Volterra, we were operating under three ERP systems. We have been consolidating those into one system over the last two years. And it so happens that in May of this year, we went live with one, with basically a third of our business. And that cut over from one system to the new system caused a slight delay in some of our billings, which also added a little bit to our receivable balance at the end of the quarter. We are now live under one system with, you know, the majority of our business. The only thing remaining to go live would be our Altera business, which is smaller, obviously, so we don't think that this poses much risk going forward. So those three things really kind of affected the cash flow in the quarter, and I think they reversed themselves pretty quickly. And then as we continue to improve our results, you'll see that show up in higher cash flow as the revenue and the profitability, you know, ultimately turns into cash. So where we're exactly going to spend our cash, I might turn that over to Andy Hendricks to talk a little bit about the systems upgrades and the equipment upgrades.

Yeah, thanks. I think Andy did a great job explaining that. it's just a transitory thing we run into each year around the second quarter and now you've got it compound with an inflection in activity which is a positive you know we're very happy that we're seeing this inflection activity in the second quarter and it moved a lot faster than we thought you know at the end of may and said that our recount was already moving faster than we thought well even since we put that so we'll take it the rig upgrades don't deliver until early

2027 so this is very encouraging from an outlook stand if you look at all the high-end equipment on the completion side right now that's very helpful andy if we would not have guessed that from the outside so thanks a lot for that explanation on the second quarter i'll turn it back your next question comes from the line of scott gruber with city group scott your line is now open please go ahead yes good morning andy and andy um i want to come back to the uh the high spec rig

commentary because it's certainly very encouraging, particularly your ability to book these high-spec rigs on longer-term contracts. Can you just provide some more color on the economics around upgrading rigs today? What is the cost point to upgrade to a top-tier status? How many rigs are upgradable in that kind of first tranche of upgradable rigs is kind of want to walk through the economics there.

So let me give you a little bit of background. You know, for the last 15 years in the industry, the primary rig spec revolved around a 50,000 pound load, which over time we've migrated up into the, you know, 800, 850 range in terms of 850,000 pound load capacity. But what's It's becoming clear with the longer laterals and the Permian, some of the deeper wells and other plays, you know, the technical need for higher capacity has evolved to where now hats off to our engineering teams who've looked at the existing rig structures that we operate in the field. They've come up with some very capital efficient way, actual load capacity of those rigs, increased setback capacity, which, you know, refers to the amount of drill pipe that the drilling or it can hold for the longer laterals to be efficient, or even on the substructure and the mast combined to increase the load capacity. And so their efficiency and able to be able to do this allows us millions of dollars, let's call it, signing term contracts to do this. We're seeing higher pricing to be able to do this, and we're getting a quick payback. We've probably got in the range of, I'll call it, you know, 10 to 15 rigs that we can do that to. And then we're also doing some larger structuring you know we're going to increase the rig capacity even more for some of the deeper plays and when we do that the upgrade is much more significant but we're also signing three plus year term contracts to be able to pay back you know within the hope that helps no it does appreciate the color um and then just wanted to turn to the third quarter outlook for drilling.

The step up in GP to 145, it's up about 8%. It kind of matches the step up in rate count. It looks like kind of broadly flat margins. You mentioned rates are inflating and you should get some fixed cost absorption on the step up. But our reactivation cost, kind of preventing margins from stepping higher or any other color on what's kind of capping the margins and how that fades away.

Yeah, I think that we'll see working capital and move. So all of that's embedded in the guide. Yeah, I would say that.

I appreciate the color. I'll turn it back.

Your next question comes from the line of Derek Podheiser with Piper Sandler. Your line is now open.

Please go ahead. hey good morning everybody um sorry if i missed this in the opening comments so one of the to expand more on the argentina opportunity that you have um you know your partnership with archer down there that you leased a couple rigs um and maybe just broadly latin america you're closing down colombia the legacy pioneer assets but maybe just speak to the potential opportunity in argentina sounds like they need a lot of rigs down there and what you could see uh for that and then potentially be doing more than to just kind of leasing through through a partnership and actually sending rigs down there you operating them and then just just building a bigger business down in argentina maybe other areas in latin america yeah thanks jerek so yeah we're pleased

with the opportunity that we had to work with archer and their dls division some capacity out there may be a little bit more opportunity for us to work with them we certainly recognize that over the next years not just you know but even you know the projections on previous rig count increases to our sector, sport pipelines, you know, being completed and there's interesting. Great.

Exciting opportunity. Switching over to FRAXO, you know, clearly, clearly you've posted some good wins there. Your incremental margins really stood out compared to your peers this quarter. So maybe talk to us more about the ability to drive, you know, both your utilization, your pricing, obviously you're upgrading the fleet more towards that 100% natural gas burning equipment. But how we should think about the flow through of these wins that you're capturing through the back half of the year and into 2027 as the industry starts to kick off RFP season here?

Yeah, I'll say to begin with, hats off to our completions team. You know, completions has been a challenged market for three years where you've had this pressure on the market with slowing activity and a lot of downward pressure on pricing, even more so than in other parts of oil field services. And so, you know, as we got to this inflection point, Our team did a great job working with our customer discussions, which, you know, it's a big shift after three years to all of a sudden talk about pricing. But our team was able to land a large number of price increases in the second quarter. I believe they're going to get more pricing. So I think that continues because the market is tight. The market is essentially sold out of everything at the high end that needs natural gas. and when it comes to the schedule they did a great job rounding out the end of the second quarter which could have potentially had some challenges but it didn't and then I would say third quarter is solid you know appreciate all the color Andy I'll turn it back your next question

comes from the line of Stephen Gingaro with Stifle your line is now open please go ahead Thank you.

Good morning, everybody. Good morning, Steve. So can you talk a little bit about, you know, kind of where we stand on the completion side from a price perspective, like maybe relative to, you know, the trough that we saw or maybe prior cycles, but how do we think about kind of where we stand and what type of improvements we might be able to see over the next several quarters?

Yeah, thanks for that question. You know, if you look over the last three years, we estimate in general, average pricing is probably down 30%, maybe a little bit more across the board. And so that's a big, you know, that has a lot of impact on margin when that happened. inflection in drilling activity that we're seeing in Q2, demand from EMPs to get wells online, pricing is moving up a few quarters with the amount of rig capacity that we see going into the market, the amount of new wells being drilled at a fast pace, and the lack of available high-end completion equipment. There's a good chance for us to get part, or if not all, and I'll call it recovery back into the market for all.

Great. Thank you. And then the other question I have along the same lines is when we think about the assets that are out there, and it feels like clean burning assets are very tight, how does the arb between diesel and gas play into the pricing discussions now?

And is it in fact a distinct positive because of where diesel prices have gone or is it or does that not have too big an impact on the pricing discussions yeah it's it's an interesting question with with an interesting history because you know in the evolution of using gas for frack it really started in the northeast where you had a lot of access to dry gas good quality gas in the basin but you know over the last five six years it's really ramped up in the Permian we you know you've got bottlenecks of getting gas out of the basin you know you've got the basin gas prices very low and so even though you know even without diesel moving up arbitrage just because gas was so low in the Permian Basin now it's even more pronounced with diesel prices moving up and gas still trapped there's a big demand just because of that and of course that drives compresses natural gas delivers natural gas treats it at the well site blends it with fuel gas and so that drives activity okay great thank you for the details Thanks, Stephen.

Your next question comes from the line of Keith McKay with RBC Capital Markets. Keith, your line is now open. Please go ahead.

Good morning, just like to maybe return to the margin question for completions. Can you just give us a little bit more color, if possible, on the mix of revenue growth versus incremental margin embedded in the Q3 guidance? and maybe just some of the qualitative push-pulls between the two quarters as well?

I'll start. I'll let Andy weigh in as well. You know, a lot of it, just to tell you, the Q3 schedule is a little more solid than Q2 with less white space. But the price increases are overall horsepower deployed in general, heavily flat. We continue to add the higher-end emerald 100%.

Maybe just turning to drilling products, which has kind of been the sleeper division over the last quarter and within the guidance, at least relative to our numbers, can you just talk about some of the Middle East and, you know, tungsten inflation challenges that division has faced? Are those fully or mostly abated now, and will that factor into some of the improvement going forward, or is it strictly activity incrementals from here?

Yeah, I'll start with the Middle East, a couple countries in specific. Our team in Oman is doing a great job. They continue to deliver there and improve, you know, the amount of sales. Arabia has got inventory that, now in terms of tungsten prices, sure, it's gone up for everybody across the board. You know, it's got a lot of use outside of our industry, especially, you know, in the conflict in the Middle East region. And so, you know, that's a big component of what we call a matrix body drill bit. but we're seeing a shift to the tungsten, and that affects everybody across the board. Customers are willing to use some of the steel body bits as well.

Okay, thanks a lot.

Your next question comes from the line of Jim Rolison with Raymond James. Your line is now open. Please go ahead.

Hey, guys. Morning, Jim. Andy, you talked a little about adding some of the CapEx to add new emerald gas equipment on the frack side replacing diesel that you expect to retire you talked about pricing that's you know on its way back up and maybe recaptures where you were before all this down downturn kind of started at what point would you consider actually adding to your total fleet horsepower given the maybe market opportunity set you see for you know growing well count going into next year?

So, I appreciate that question, because it really kind of speaks to, you know, what we see as opportunities in the market. And right now, we think price, the fact that the market is tight and essentially sold out of everything that can burn natural gas, you know, allows very low levels over the last three years. And I think that's more important to us for slots that are penciled in for us without putting deposits down.

So, we do have access to get what we have yet to make sense and and then just as a follow-up maybe any updates on you know your kind of turn well jv and with ad knock and given their kind of plans once all this stuff settles down you know when you get to the second phase of that opportunity set you know just where are you in that process because i think right now you're just providing technical expertise but i think there was a longer term opportunity potentially for actually equipment ads and love to get an update.

But ADNOx plans are over there. I will tell you we continue to participate in the Turnwell Drilling and Completion activity through advising and deficiencies. It continues over there.

Appreciate it.

Your next question comes from the line of Alexa Breno with Goldman Sachs. Alexa, your line is now open.

Please go ahead. hey thanks team and appreciate you taking our question we just wanted to ask a follow-up about on some of these pricing increases can you just talk about the sustainability of these pricing gains and then are you able to give us a sense of how leading edge day rates are trending relative to your average fleet yeah so i'll break it into drilling and completion so when you look at the drilling rig business uh you know we were getting price increases on the new agreements and contracts we were signing up in the second quarter and you know on average in the 10 to 15 percent range some may be a little lower but some may have been higher as well certainly very sustainable because they're locked into contracts and the market is demanding increasing capacity with upgrades and when we do those upgrades that's even a higher day rate as things get locked into in terms of completions you know we're really working hard on being pushed down for three years If you look at the Q2 and what we think will do, it really goes back to that through any period of time or cycle, attrition is real.

And as we look across the industry participants in the competitive landscape, there's probably less capital being devoted into the completions market today than there has been in past cycles. And so we feel like we're in a really good spot to be able to support the pricing improvements that we've had and add to them as we go through the cycle.

Thanks. That's very helpful. We'll turn it back.

Thanks, Alex.

Your next question comes from the line of Eddie Kim with Barclays. Your line is now open. Please hold. Your line is now open. Please go ahead.

Hey, good morning. So you provided an updated guidance in mid-May, not long after first quarter results. It actually surpassed that updated guidance. So clearly there are some unexpected surprises to the upside, particularly in the completion services business. Could you maybe talk about where those bright spots were that surpassed your initial expectations, strengthened any particular basin or customer type maybe? And sort of just related to that, I'm a little surprised at how quickly the completion services business has inflected for you guys, especially because we've only seen the recount increase here in the past two months and you sort of assume kind of a six-month lag at least so um i would have thought that the inflection might have happened later in the year in that business so could you talk about how you were able to realize the benefit uh so quickly and in any um uh any bright spots in that business yeah so let Let me start by talking about the contract drilling side of the business first.

You know, when we did our earnings call in April, we had a projection on what we thought the rig count was going to do. And it wasn't, you know, a week or so after that, that, you know, we got into more discussion. You know, as we got into the season of getting out to see investors, we thought it was important to get out there with a signal to the market then that we were seeing that rig count moving Well, it wasn't long after we put out the eight request, put our rig count. We saw some tightening in the completions market in that second. We are going to see, you know, tighter completions in the market is the completion side, and that's when the market is really going to show how tight it is. So, yes, we're getting some pricing increases in Q2 and Q3 in the second half of this year, but I think you'll see even larger early next year. But for now, we're just focused on the pricing recovery.

Understood. That's very helpful, Colin. Thank you. uh my follow-up is just on uh shareholder return apologies if i missed this but uh previously you talked about returning at least 50 of adjusted free cash flow to shareholders this year has that target been maintained or or updated yeah there um there's no update to that that's still our commitment um and and we fully expect to do that okay great thank you i'll turn it back thanks Your next question comes from the line of Dan Kutz with Morgan Stanley.

Dan, your line is now open. Please go ahead.

Hey, thanks.

Good morning, Dan.

So I just wanted to come back to a question on free cash flow. I guess, how would you think about the free cash conversion of the business kind of through cycle, I guess, Just to throw a number out, if you look over various historical periods, around 40% free cash conversion kind of seems like what the business has averaged in the past, but obviously the business has evolved over time. So, yeah, anything that you'd share on kind of through cycle or normalized free cash conversion potential? And could you see potential for 2027 to be above that normalized level?

Yeah, I agree with everything you said. Yeah, I think 40% is typically the target that we're looking at. The 27th, you know, it's shaping up to be on the right side of the through cycle. So I would expect that perhaps we could see it higher than the target that we're always kind of focused on.

That's really helpful. And then maybe just on the Columbia business exit, could you just kind of give us a little bit of history on that business? um i just looking back i think when um through the pioneer acquisition there was there was eight columbia rigs that came along with that i saw a note that they were pad capable so thought you know they were decent decent quality relatively you know somewhat newer rigs and and you know latin america overall obviously argentina but latin america overall has been an area of strength So just, you know, kind of trying to square the – you guys disclosed Columbia revenue so you could see that it kind of slid two years ago, and then last year, you know, came down substantially. Were any of those rigs relocated to other regions? Were any of those rigs trapped?

Yeah, just, you know, anything that you could share on the history of that business up until the decision to exit that you guys disclosed yesterday? thanks yeah thanks so when we did the acquisition of pioneer energy services our focus was on the contract drilling portions of the business and you know we did columbia came along with the package with but these drilling rigs either rigs was the team down there that were operating these rigs is a great team and they did a great job with the tools that they have there's been a shift in the market down there just like in other markets to go to newer ac high spec rigs and And we looked seriously at moving AC high-spec rigs down to that market, but you had a change in the politics in that country as well, which really kind of created a headwind for, you know, drilling oil and gas, any kind of. And so, you know, with the change in the politics in the country, the overall drilling, and these being SCR rigs are just not the rigs that people want to work in that country. Unfortunately, that's.

Yeah, you know, 75% of that value was stuff that came over with the acquisition. So it wasn't that we, you know, added a lot into that market. You know, we did move some spares and pieces of equipment that were no longer really suitable for the U.S. market down there, but had a home in Columbia as long as it was active. And as it's become less active for us, we just thought it was the right time to exit the market and run all of that off.

Yeah, Columbia wasn't the driver for the acquisition of Pioneer Energy Services. It just happened to come along with the package. We were very pleased with the AC high-spec rig.

That all makes sense and is really helpful. Thanks a lot. I'll turn it back.

Your next question comes from the line of Sean Mitchell with Daniel Energy Partners. Sean, your line is now open. Please go ahead.

Thanks for squeezing me in, guys. Nice. Andy, you and others in the industry have talked about the privates kind of leading the rig count charge here recently. Most of that's been oil directed, certainly in the second quarter. Can you talk a little bit about your outlook for gas activity in terms of rigs or any of the upgrades you're doing for gas and just gas activity in general? Obviously, gas rig count, I think, was actually down during the quarter and oil was up, but just gas activity in general and your outlook.

Yeah, thanks, Sean. So, you know, while there's a big focus on what's happening in the oil basins, you know, with oil trading at the levels that's been trading over the last quarter and the Strip, you know, at 70-plus these days, also deploying drilling rigs into gas markets, we're in discussions with gas E&Ps for further. And so, potential growth in the Permian and other gas or other oil markets, it's not just the oil markets that are going to.

Great. Thanks for the color.

There are no further questions at this time. I will now turn the call back to Andy Hendricks for closing remarks.

I'd like to thank everybody for joining us on the call this morning. It's been an exciting time in the industry with the inflection that we've seen rig activity and delivering term contracts this year and also into early 2027. And then the pricing recovery that we're getting in completions as well in the second half of 2026. and also the improvement in free cash flow that we expect to go. Again, thanks for everybody for dialing in today. I also want to thank our teams at Patterson UTI for everything they've done and all the hard work to help drive this inflection point.

This concludes today's call. Thank you for attending. You may now disconnect.