Patterson-UTI Energy, Inc. (PTEN) Q2 2026 Earnings Report, Transcript and Summary

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.

Thank you, operator. Good morning and welcome to Patterson-UTI's earnings conference call to discuss our second quarter 2026 results. With me today are Andy Hendricks, President and Chief Executive Officer, and Andy Smith, Chief Financial Officer. As a reminder, statements that are made in this conference call that refer to the company's or management's plans, intentions, targets, beliefs, expectations or predictions for the future are considered forward-looking statements. These forward-looking statements are subject to risks and uncertainties as disclosed in the company's SEC filings, which could cause the company's actual results to differ materially. The company takes no obligation to publicly update or revise any forward-looking statements. Statements made in this conference call include non-GAAP financial measures. The required 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, Mike. 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 elevated. That backdrop is likely to remain part of the market for some time. 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 oil field 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 oil field 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. During the 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 achieved 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 or less. Even as the U.S. rig count has increased over the past several months, public E&Ps 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 E&Ps have responded more quickly to higher oil prices and are now driving a meaningful increase in drilling activity. Still, our discussions with the public E&Ps 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 and prioritizing rigs with greater hook load and pipe racking 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. 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. Overall, we expect oil-directed activity to improve further into 2027. Private E&Ps are leading the initial recovery. 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. In drilling services, rig activity recovered faster than we expected during the quarter. Pricing on new contracts increased by approximately 10%-15% versus first quarter levels. Upgraded rigs are being deployed at day rates several thousand dollars per day above standard super-spec 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. Customers are reluctant to lose active, proven rigs and crews, given the startup costs and recrewing needs associated with reactivating cold stacked equipment. That dynamic is also supporting additional pricing improvement in the Permian. As E&Ps 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 within the initial term of the agreement. The direction of the market is clear. Roughly half of recent wells drilled have laterals longer than 2 mi compared with about one-third last year. 4+ mi laterals now represent more than 10% 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 E&Ps, these trends reflect where U.S. shale development is headed. 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 moved 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. Frac 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 profitability. 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 frac equipment. 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 frac 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 the market. At the beginning of the year, we expected our available frac 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 drive, 100% natural gas-powered Emerald frac 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 substantially by natural gas. 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. Our Drilling Product segment delivered an excellent quarter in a challenging operating environment, achieving its highest revenue since we acquired Ulterra in 2023. The conflict in the Middle East created disruption across logistics, supply chain, and activity levels in several important markets. Our team stayed focused and managed effectively through those challenges while keeping employee safety at the forefront. Even with those headwinds, along with the seasonal impact of spring break-up 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 business. At the same time, our U.S. business remains a steady foundation for the 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 to 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. oilfield 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. 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 shareholders. As the year has progressed, we have 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. 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. 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 to review 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 Colombia, 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. 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. 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 build 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've required an incremental capital investment. We believe the 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 Colombia, 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. 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. We expect to exit the 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 frac 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. 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. 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 E&P interests. For the third quarter, we expect adjusted gross profit and 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 the year. 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. 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, 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 oilfield 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, Saurabh.

Morning, Saurabh.

Andy, it's really, really heartening to see the significant improvement in activity and pricing, I think, on the rig side. You might have troughs in the high 80s. You are now at 99. You expect to end the quarter at 100+. Frac is 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 that the frac fleets are busy, right? How should we think about what kind of duration are you getting on these rigs as they're going out to work? I think I heard you say that your discussions with the public E&Ps are gaining traction, so maybe help us think along those lines, private versus public customers, what you're hearing from them.

Yeah. Being a drilling contractor, we get a lot of advanced conversations around what customer plans are in the U.S. As everybody's seen in the data, and we discussed this morning, it's certainly the private E&Ps that are moving quicker than the publics. When we reactivate a drilling rig, we 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. Every rig that's getting reactivated is going to a program somewhere, and rigs that are getting upgrades are signing long-term contracts, six months in general, but some even longer. 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. That's the kind of visibility we have today just with the privates that are moving quickly to deploy rigs. We're also in discussions today with public E&Ps. 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 firming up in the second half of this year, and you'll probably hear more about it from their own disclosures. I don't want to call anything out in terms of specifics or areas because, it's up to the publics to make those disclosures themselves. We're certainly in those discussions. The interesting thing, of course, is with the rig count ramping up as fast as it has, the well count's ramping up and frac activity and completion activity will follow. That's why we're very encouraged about completion activity in the second half of this year and also going into 2027. Combine that with the shortage of high-end equipment, it sets things up very well for oilfield services.

No, that's very helpful, Andy. Thank you. Then my follow-up is more on the free cash flow side of things. Of course, the second quarter was weighed down by working capital, which is normal for this time of the cycle. Your activity ramps up, your working capital ramps up. I think, Andy, you were talking about free cash flow improving significantly in 2027. I know it's a little early to talk about 2027, but maybe give us some directional color on what to expect for 2027, 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? Just some color on where we should expect free cash flow to go next year.

Yeah. Hey, if you don't mind, Saurabh, what I'd like to do is maybe give a little bit more color on free cash flow during the quarter, then Andy and I can talk about investments going forward. If you look at our free cash flow in the second quarter, we've talked about this in the past, seasonality, we always sort of have a seasonally low quarter in the second quarter. The first reason for that is because, 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 you then ramping up your cash flow for those customers until later in that year. 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. 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, we get those billings out, and they end up sitting in receivables at the end of the quarter. That's the use of cash. Finally, the third thing that I would point out, and we've talked about this in the past as well, after the merger with NexTier and the acquisition of Ulterra, 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 basically a third of our business. 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 the majority of our business. The only thing remaining to go live would be our Ulterra business, which is smaller, obviously. We don't think that this poses much risk going forward. Those three things really affected the cash flow in the quarter, and I think they reversed themselves pretty quickly. Then as we continue to improve our results, you'll see that show up in higher cash flows as the revenue and the profitability ultimately turns into cash. 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. We're very happy that we're seeing this inflection activity in the second quarter, and it moved a lot faster than we thought. At the end of May, we put out an 8-K, an investor presentation with an update, and said that our rig count was already moving faster than we thought. Well, even since we put that out at the end of May, the rig count has moved even faster. Really encouraged by that, and of course, that's a draw on working capital, but at the end of the day, that's a positive. We'll take it. We were very clear that cash flow is going to improve in the second half of this year. We're not concerned about that at all. We're just really pleased to see the market where it is and where it's going, not just for this year, but also into 2027. A number of the rig upgrades that we have booked will be delivered this year, but some of the rig upgrades that we have booked and we'll be signing long-term contracts on don't deliver until early 2027. This is very encouraging from an outlook standpoint, and it also drives completion activity. You've already had another 50 rigs roughly added to the industry rig count with no real increase in completion capacity. If you look at all the high-end equipment on the completion side, we're essentially sold out.

Right. No, that's very helpful, Andy. We would not have guessed that from the outside. 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 Citigroup. Scott, your line is now open. Please go ahead.

Yes. Good morning, Andy and Andy.

Good morning.

I want to come back to 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 first tranche of upgradable rigs? Just want to walk through the economics there.

Let me give you a little bit of background. For the last 15 years in the industry, the primary rigs spec revolved around a structure capacity of 750,000 lbs load, which over time we've migrated up into the 800,000 lbs, 850,000 lbs range in terms of 850,000 lbs load capacity. What's becoming clear with the longer laterals in the Permian, some of the deeper wells, and other plays, the technical need for higher capacity has evolved to where we need to push it up to 1 million pounds. Now, hats off to our engineering teams who've looked at the existing rig structures that we operate in the field today, and they've come up with some very capital efficient ways to upgrade the structural load capacity of those rigs, increase setback capacity, which refers to the amount of drill pipe that the drilling rig can hold for the longer laterals to be efficient, or even on the substructure and the mast combined to increase the load capacity for moving large, heavy casing strings that the other previous generation of rigs couldn't move. Their efficiency to be able to do this allows us to spend in low single digit millions of dollars, let's call it $2 million, on a lot of these rigs and get a payback within a year. Signing term contracts to do this is what we're doing. We're seeing higher pricing to be able to do this, and we're getting a quick payback. Really encouraged by this. We've probably got in the range of, I'll call it, 10 to 15 rigs that we can do that to this year and into early next year. We're also doing some larger structural upgrades where we're going to increase the rig capacity even more for some of the deeper plays. When we do that, the upgrade is much more significant, but we're also signing 3+ year term contracts to be able to do that. We'll get payback within the early period of those terms. Hope that helps.

It does. Appreciate the color. 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 rig 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. Are reactivation costs kind of preventing margins from stepping higher? Any other color on what's kind of capping the margins and how that fades away?

I think that we'll see probably a similar amount of reactivation costs that we saw in 2Q and 3Q. We'll also have a little bit of, as we kind of finalize our exit from Colombia, we'll have a little bit of trailing cost there as well. We wrote off most of working capital and whatever assets we had left, but there's still cost associated with kind of exiting that operation that will linger for a quarter or two. All of that's embedded in the guidance, Scott. I would say that that's a little bit of what's holding those margins back from increasing a little bit more or what you're seeing a little bit more.

Okay. I appreciate the color. I'll turn it back. Thank you.

Thanks.

Your next question comes from the line of Derek Podhaizer with Piper Sandler. Your line is now open. Please go ahead.

Hey, good morning, everybody. Sorry if I missed this in the opening comments. I wanted to expand more on the Argentina opportunity that you have. Your partnership with Archer down there, that you leased a couple rigs. Maybe just broadly Latin America, you closing down Colombia, the Legacy Pioneer assets. Maybe just speak to the potential opportunity down in Argentina. It sounds like they need a lot of rigs down there, and what you could see for that. Then potentially maybe doing more than to just kind of leasing through a partnership and actually sending rigs down there, you operating them, and then just building a bigger business down in Argentina, maybe other areas in Latin America.

Yeah. Thanks, Derek. Yeah, we're pleased with the opportunity that we had to work with Archer and their DLS division down in Argentina and lease them a couple rigs and allow us to take some capacity out of the U.S. market and move it down there. There may be a little bit more opportunity for us to work with them. We certainly recognize that over the next four to five years, there's an increase in activity in Argentina, and we're part of those discussions with every operator down there, and also operators that are looking to go down there who aren't down there yet. I would say there's an opportunity for us down there, and it's still early days. Argentina's had a lot of challenges over the years, not just big picture macro monetary issues, but even the projections on previous rig count increases in Argentina, specific to our sector, have always been a little bit overinflated. I think that could change going forward. Now that you have export pipelines being completed and there's more infrastructure being put in down there. It's interesting. Over the last few years, there have been rigs available in that market and no need to bring new rigs in. Going forward, there's likely a need to bring new rigs into the country. We'll just have to wait and see how that works out for us. I appreciate the question.

Great. It's an exciting opportunity. Switching over to fracs, though, clearly you've posted some good wins there. I mean, your incremental margins really stood out compared to your peers this quarter. Maybe talk to us more about the ability to drive both your utilization, your pricing, obviously you're upgrading the fleet more towards that 100% natural gas burning equipment. 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?

I'll say to begin with, hats off to our completions team. 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 oilfield services. As we got to this inflection point, our team did a great job working with our customers to have those discussions, which it's a big shift after three years to all of a sudden talk about pricing increases. 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 increases in Q3 and Q4 this year. 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. 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. I would say third quarter is solid. We just don't see a lot of white space in the third quarter, maybe compared to some previous quarters. Just because of the increasing activity that's out there in the market, E&Ps wanting to get wells completed, get wells online for production. The schedule is definitely rounding out solid for the third quarter.

Great. Appreciate all the color, Andy. I'll turn it back.

Thanks, Derek.

Your next question comes from the line of Stephen Gengaro with Stifel. Your line is now open. Please go ahead.

Thank you. Good morning, everybody.

Morning, Steve.

Can you talk a little bit about kind of where we stand on the completion side from a price perspective? Maybe relative to the trough that we saw, or maybe prior cycles. 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. 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. That has a lot of impact on margin when that happens. With this inflection in drilling activity that we're seeing in Q2, demand from E&Ps to get wells online, pricing is moving up. Over the next 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 a large part or, if not all of this pricing recovery, and I'll call it recovery, back into the market for oil field services over the next few quarters.

Great. Thank you. Then the other question I had 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? Is it, in fact, a distinct positive because of where diesel prices have gone? Does that not have too big an impact on the pricing discussions?

Yeah, it's an interesting question with an interesting history because in the evolution of using gas for frac, it really started in the Northeast where you had a lot of access to dry gas, good quality gas in the basin. Over the last five, six years, it's really ramped up in the Permian. You've got bottlenecks of getting gas out of the basin. You've got the basin gas prices very low. Even without diesel moving up over the last quarter or so, you still have this 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 in the basin. Yeah, there's a big demand just because of that. Of course, that drives our division within completion that compresses natural gas, delivers natural gas, treats it at the well site, blends it with field gas, and so that drives activity for us in that sub-segment as well.

Okay, great. Thank you for the details.

Thanks, Stephen.

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

Hey, thanks, and good morning.

Morning, Keith.

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. A lot of it just has to do with price increase. I would say the Q3 schedule is a little more solid than Q2 with less white space, that helps as well. The price increases are really what's driving the improvements in margin. I wouldn't say overall activity, overall horsepower deployed in general hasn't changed. We expect that to be relatively flat. As we discussed, we continue to add the higher-end Emerald 100% natural gas burning systems and retiring the diesel, those work at a higher margin as well. You've got general price increases, you've got higher margins on newer technology going out, you've got a more solid schedule in the third quarter.

Yeah, I don't have a lot to add to that. The majority of it is price. Obviously, as we started to see the pricing improvements layer through the second quarter, those stay in effect through the third quarter, then additional price improvements on areas and customers where we hadn't actually achieved anything as of yet. We feel really good about the incremental margins coming in in the third quarter.

Okay. Thanks for the color. 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 tungsten inflation challenges that this division has faced? Are those fully or mostly abated now? 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 the amount of sales, improve their competitive position in Oman. Saudi Arabia's gone through various challenges with shutting down offshore. Land drilling is picking up with a rig count increase in Saudi. Saudi also had a shift where Aramco decided to use previous drill bits that they had in inventory that may have only had one run on them and reuse those bits. Our team in Saudi, at our manufacturing center there, has qualified themselves with Aramco to do rebuilds on those bits. There's times where we're not necessarily manufacturing a new one, but we're rebuilding the old ones. We're becoming known as one of the highest quality companies for doing that in Saudi Arabia. We see that improving, and at some point, hopefully, the offshore drilling can pick up again too. With the land rig activity increasing and working through the backlog of inventory that Aramco has, it's long-term upside for us over there too. In terms of tungsten prices, sure, it's gone up for everybody across the board. It's got a lot of use outside of our industry, especially, in the conflict in the Middle East region. That's a big component of what we call a matrix body drill bit. We're seeing a shift to customers willing to use what we call a steel body drill bit, where we machine the steel, we arrange the cutters, raise them in place, and coat the steel where necessary. We're seeing an increased use of that steel. It's partially mitigating the higher cost of the tungsten. We're still gonna use tungsten, we're still gonna deliver matrix bits. That affects everybody across the board, not just us. That's an industry-wide for all drill bit suppliers. Pleased to see that some of the customers are willing to use some of the steel body bits as well.

Okay. Thanks a lot.

Thanks.

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

Hey, guys. Morning.

Morning, Jim.

Andy, you talked a little about adding some of the CapEx to add new Emerald gas equipment on the frac side, replacing diesel that you expect to retire. You talked about pricing that's on its way back up and maybe recaptures where you were before all this 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 growing well count going into next year?

I appreciate that question because it really kind of speaks to what we see as opportunities in the market. Right now, we think price recovery in completions is a big opportunity. The fact that the market is tight and essentially sold out of everything, you can burn natural gas, allows the entire industry to get some recovery in pricing that's been pushed down to very low levels over the last three years. I think that's more important to us right now than adding capacity to the market. We have the benefit of being Caterpillar, one of their largest customers in the U.S. We use Caterpillar engines across all of our drilling business and our completions business. We have a very good relationship with that company. We have access to the slots in 2027, slots that are penciled in for us without even potentially putting deposits down. We do have access to get the equipment if we decide to add fleets. We haven't made that decision yet. We're focused on price recovery in the near term, and then we'll continue to look at the market, evaluate it as it changes, and we know there's gonna be demand for higher capacity next year, but we have yet to pull the trigger on that.

Makes sense. Just as a follow-up, maybe any updates on your kind of Turnwell JV and with ADNOC and given their kind of plans once all this stuff settles down, when you get to the second phase of that opportunity set, 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 adds and love to get an update.

Sure. I don't want to over speak for what ADNOC's plans are over there. I will tell you, we continue to participate in the Turnwell drilling and completion activity, through advising and coaching and mentoring over there to help improve efficiencies. Work still continues over there. They're still proving out costs on phase I to evaluate what it takes to get to phase II, that's probably about the most I can say at this point.

Got it. Appreciate it.

Thanks.

Your next question comes from the line of Alexa Bruno 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. I'll break it into drilling and completion. When you look at the drilling rig business, we were getting price increases on the new agreements and contracts we were signing up in the second quarter and, on average, in the 10%-15% range. Some may be a little lower, but some may have been higher as well. Certainly very sustainable because they're locked into contracts. The market is tight for rigs. The market is demanding increasing capacity with upgrades. When we do those upgrades, that's even a higher day rate as well. Those kind of things get locked into term contracts. In terms of completions, we're really working hard on pricing recovery after getting pushed down for three years. If you look at the sustainability of what we're getting so far in Q2 and what we think we'll get in Q3 and Q4, it really goes back to the tightness in this market. I know there's reports out there that say there's a lot of frac fleets available, and a lot of those frac fleets are older Tier two diesel in the Midland Basin, and that's not what our customers in the Delaware or other basins are looking for. They need equipment that can burn natural gas. It's the most cost-efficient use of fuel in those basins, and they're demanding more of that. I suspect that what you'll see in the second half of this year is certain E&Ps willing to pay more than other E&Ps, and you may even see shifts of frac fleets from one E&P to another because somebody else is willing to pay more for that frac fleet, until sometime in the future when companies are willing to add capacity, which we don't see yet.

Yeah, I would add to that a little that, especially within the completions market, as you go through any period of time or cycle, attrition is real. As we look across the industry participants and the competitive landscape, there's probably less capital being devoted into the completions market today than there has been in past cycles. 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, Alexa.

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

Hey, good—

Your line is now open. Please go ahead.

—hey, good morning. You provided an updated guidance in mid-May, not long after first quarter results. It actually surpassed that updated guidance. 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, strength in any particular basin or a 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 rig count increase here in the past two months, and you sort of assume kind of a six-month lag at least. I would've thought that the inflection might have happened later in the year in that business. Could you talk about how you were able to realize the benefit so quickly and any bright spots in that business?

Yeah. Let me start by talking about the Contract Drilling side of the business first. When we did our earnings call in April, we had a projection on what we thought the rig count was gonna do, it wasn't a week or so after that we got into more discussions with E&Ps about putting out drilling rigs at a faster pace. As we got into the season of getting out to see investors, we thought it was important to get out there with a mid-quarter update on that and put out a fresh investor presentation with an 8-K at the end of May. We signaled to the market then that we were seeing that rig count moving faster. Well, it wasn't long after we put out the 8-K that we got into even further discussions in the rig count request from E&Ps came in even hotter than what we thought, and that's why you saw the rig count moving up. It's very public because we put our rig count on our website every day, posts around midday, and so you could see our rig count moving at even a faster pace than what we said at the mid-quarter update. That was already moving. It wasn't just us, the industry was moving as well. And so you saw some tightening in the completions market in that second quarter that allowed us to push pricing with a number of the customers that we were working for as we got to the point of discussing agreements with some of those customers. The rig count continuing to move up, we are gonna see tighter completions going into Q3 and also Q4. What you haven't really seen yet in the market is the real demand of adding 50 rigs into the market. You're not gonna see that demand on the completion side until later this year and into 2027, and that's when the market is really gonna show how tight it is. Yes, we're getting some pricing increases in Q2 and Q3 and the second half of this year, but, I think you'll see even larger price recovery for us, which allows us to have more constructive thoughts about adding capacity potentially later this year and early next year. For now, we're just focused on the pricing recovery in completions.

Understood. That's very helpful color. Thank you. My follow-up is just on shareholder return. Apologies if I missed this, but previously, you talked about returning at least 50% of adjusted free cash flow to shareholders this year. Has that target been maintained or updated?

Yeah. There's no update to that. That's still our commitment, 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.

Morning, Dan.

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. Obviously, the business has evolved over time. 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? Thanks.

Yeah. I agree with everything you said. I do think that as we look at 2027, it is shaping up to be on the right side of the through cycle. I would expect that perhaps we could see it higher then. Yeah, 40% is sort of the target that we are always kind of focused on through cycle.

Great. That is really helpful. Then maybe just on the Colombia business exit, could you just kind of give us a little bit of history on that business? Just looking back, I think when through the Pioneer acquisition, there was eight Colombia rigs that came along with that. I saw a note that they were PAD capable, so thought they were decent quality, relatively, somewhat newer rigs. Latin America overall, obviously Argentina, but Latin America overall has been an area of strength. Just kind of trying to square the you guys disclose Colombia revenue, so we could see that it kind of slid two years ago, and then last year came down substantially. Were any of those rigs relocated to other regions? Were any of those rigs scrapped? Yeah, just 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. When we did the acquisition of Pioneer Energy Services, our focus was on the Contract Drilling portions of the business, and we did a subsequent quick sale of other elements of that business that we did not find to be strategic for us. Colombia came along with the package with eight drilling rigs, but these drilling rigs were the older SCR type. The capacity of the rigs was good, in some cases, 1 million pounds, but they are SCR rigs. We believe we worked those rigs as long as we could in Colombia. The team down there that were operating these rigs is a great team, and they did a great job with the tools that they had. There has been a shift in the market down there, just like in other markets, to go to newer AC high-spec rigs. We looked seriously at moving AC high-spec rigs down to that market. You had a change in the politics in that country as well, which really kind of created a headwind for drilling oil and gas wells and the ability for us to kind of capture any kind of upgrade in that market that made any sense. With the change in the politics in the country, the overall drilling activity has just slowed down. These being SCR rigs are just not the rigs that people want to work in that country or even some of the others. Unfortunately, that's just kind of the life cycle of that type of technology. Then you have the headwind of the change in the direction of the government and wanting to drill oil wells at the same time.

Yeah. I would also add just on what was written off in the quarter, 75% of that value was stuff that came over with the acquisition. It wasn't that we added a lot into that market. 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 Colombia as long as it was active. As it's become less active for us, we just thought it was the right time to exit the market and write all of that off.

Yeah. Colombia 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 rigs that we got in that transaction for the U.S. market.

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

Thanks.

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. 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. While there's a big focus on what's happening in the oil basins, with oil trading at the levels it's been trading over the last quarter and the strip at 70+ these days, we're actually also deploying drilling rigs into gas markets. We're in discussions with gas E&Ps for further delivery into gas markets, and we will be signing some term contracts on those deliveries as well. While we're very focused on potential growth in the Permian and other oil markets, we will see some increase in drilling activity in the gas markets, and that's good for us. That'll round us out as well. Pleased that it's not just the oil markets that are going to take some of these upgraded rigs, but some of the gas markets will as well.

Great. Thanks for the color.

Thanks.

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 in the second quarter, the increasing rig activity that we're seeing through this year, and delivering term contracts this year and also into early 2027. Then the pricing recovery that we're getting in completions in second quarter, and then what I think we'll get as well in the second half of 2026, and also the improvement in free cash flow that we expect to get in the second half of this year as well. Again, thanks, 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 that we're in. Thank you.

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