Patterson-UTI Energy, Inc. Aktie

Hello, everyone. Thank you for joining us, and welcome to Patterson-UTI's Second Quarter 2026 Earnings Conference Call. [Operator Instructions] 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 reconciliations 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, 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 elevated. 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.

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 gain 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 in 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 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.

Overall, we expect oil-directed activity to improve further into 2027. Private E&Ps 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.

In Drilling Services, rig activity recovered faster than we expected during the quarter. Pricing on new contracts increased by approximately 10% to 15% versus first quarter levels and 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 and customers are reluctant to lose active proven rigs and crews given the start-up 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 miles compared with about 1/3 last year. And 4-mile plus laterals now represent more than 10% of recent wells, roughly 4x 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, 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 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 and 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 but 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 in completions has 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 by 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 Products segment delivered an excellent quarter in a challenging operating environment, achieving its highest revenue since we acquired Alterra 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 forefront. 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 business. At the same time, our U.S. business remains a steady 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 are 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 the 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, 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 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, 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 will review the financial results for the quarter.

Thanks, Andy. Total reported revenue for the quarter was $1.228 billion, 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 noncash charges totaling $21 million related to the exit of our contract drilling business in Colombia as well as $5 million in noncash charges associated with the write-down of our minority interest in noncontrolled 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. 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 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 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 noncash 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 noncash 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 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. 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 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 15 to shareholders of record as of September 1. 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 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 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.

[Operator Instructions] Your first question comes from the line of Saurabh Pant with Bank of America.

Andy, it's really, really heartening to see the significant improvement in activity and pricing, I think, on the rig side. You might have troughed in the high 80s, you're now at $99. You expect to end the quarter at 100-plus 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 the frac fleets are busy, right? So how should we think about what kind of duration are you getting on these rigs as they are going to work? And 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?

Yes. Being a drilling contractor, we get a lot of advanced conversations around what customer plans are in the U.S. And as everybody has seen in the data and we discussed this morning, it's certainly the private E&Ps that are moving quicker than the publics. But 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. So every rig that's getting reactivated is going to a program somewhere. And rigs that are getting upgrades are signing long-term contracts, 6 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 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 discussions today with public E&Ps. They're making plans for later this year, or 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. So I don't want to call anything out in terms of specifics or areas because it's up to the public to make those disclosures themselves. But we're certainly in those discussions. And the interesting thing, of course, is with the rig count ramping up as fast as it has, the well count is ramping up and frac 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 the shortage of high-end equipment, it sets things up very well for oilfield services.

No, that's very helpful, Andy. And 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. 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?

Yes. 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, and then Andy and I can talk about investments going forward. But if you look at our free 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 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 that -- 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 year 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, we get those billings out and they end up sitting in receivables at the 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 NexTier and the acquisition of Alterra, we were operating under 3 ERP systems. We have been consolidating those into one system over the last 2 years. And it so happens that in May of this year, we went live with one -- with basically 1/3 of our business. And that cutover 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. So we don't think that this poses much risk going forward. So those 3 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 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.

Yes. 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 in 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 and investor presentation with an update and said that our rig count was already moving faster than we thought. But, even since we put that out at the end of May, the rig count has moved even faster. And so 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. So we'll take it.

We were very clear that cash flow is going to improve in the second half of this year. So 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. So 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. And if you look at all the high-end equipment on the completion side, we're essentially sold out.

Got it. No, that's very helpful, Andy. We would not have guessed that from the outside.

Your next question comes from the line of Scott Gruber with Citigroup.

And 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. So can you just provide some more color on the economics around upgrading rigs today? Kind of 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? Just kind of want to walk through the economics there.

So let me give you a little bit of background. For the last 15 years in the industry, the primary rig spec revolved around a structure capacity of 750,000 pound load, which over time, we've migrated up into the 800,000, 850,000 range in terms of 850,000 pound load capacity. But what's becoming clear with the longer laterals in the Permian, some of the deeper wells in other plays, the technical need for higher capacity has evolved to where we need to push it up to 1 million pounds.

Now our 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 mass combined to increase the load capacity for moving large heavy casing strings that the other previous generation rigs couldn't move. And so their efficiency enabled to be able to do this allows us to spend in low single-digit millions of dollars, let's call it, 2 on a lot of these rigs and get a payback within a year. And 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. So 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. And then 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. And when we do that, the upgrade is much more significant, but we're also signing 3-plus year term contracts to be able to do that, and we'll get payback within the early period of those terms. I hope that helps.

No, it does. I appreciate the color. And then I 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. But our reactivation costs kind of preventing margins from stepping higher? Or any other color on what's kind of capping the margins and how that fades away?

Yes. I think that we'll see probably a similar amount of reactivation costs that we saw in 2Q and 3Q. And 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 have left, but there's still costs associated with kind of exiting that operation that will linger for a quarter or 2. So all of that's embedded in the guidance, Scott. So yes, I would say that, that's a little bit of the -- what's holding those margins back from increasing a little bit more or what you're seeing.

Your next question comes from the line of Derek Podhaizer with Piper Sandler.

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 of rigs. 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. It sounds like they need a lot of rigs down there and what you could see for that and then potentially maybe doing more than 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 and maybe other areas in Latin America.

Yes. Thanks, Derek. So yes, 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 of 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 4 to 5 years, there is 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. So I would say there's an opportunity for us down there, and it's still early days.

Argentina has 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. So it's interesting. And over the last few years, there have been rigs available in that market and no need to bring new rigs in. But going forward, there's likely a need to bring new rigs into the country. And we'll just have to wait and see how that works out for us, but I appreciate the question.

Great. It's exciting opportunity. Switching over to frac. Clearly, you 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 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 up RFP season here.

Yes. I'll say, to begin with, hats off to our completions team. Completions has been a challenged market for 3 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. And so 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 3 years to all of a sudden talk about pricing increases. 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 increases in Q3 and Q4 this year.

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. 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. And so the schedule is definitely rounding out solid for the third quarter.

Your next question comes from the line of Stephen Gengaro with Stifel.

So can you talk a little bit about kind of where we stand on the completion side from a price perspective, like maybe relative to 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?

Yes. Thanks for that question. If you look over the last 3 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 -- that has a lot of impact on margin when that happens. And with this inflection in drilling activity that we're seeing in Q2, demand from E&Ps to get wells online, pricing is moving up. So 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 oilfield services over the next few quarters.

Great. And 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? 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?

Yes. 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. But over the last 5, 6 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. And so even though -- 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. So yes, there's a big demand just because of that. And 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 subsegment as well.

Your next question comes from the line of Keith MacKey with RBC Capital Markets.

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 2 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, so that helps as well. But 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, and those work at a higher margin as well. So you've got general price increases, you've got higher margins on new technology going out and you've got a more solid schedule in the third quarter.

Yes. 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 and those stay in effect for the third quarter and then additional price improvements on areas and customers where we haven't actually achieved anything as of yet, we feel really good about the incremental margins coming in, in the third quarter.

Okay. 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 have -- that the 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 incremental from here?

Yes, I'll start with the Middle East, a couple of 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 has gone through various challenges with shutting down offshore, but land drilling is picking up with the 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. And so our team in Saudi at our manufacturing center there has qualified themselves with Aramco to do rebuilds on those bits. And so there's times where we're not necessarily manufacturing a new one, but we're rebuilding the old ones. And we're becoming known as one of the highest quality companies for doing that in Saudi Arabia. And so we see that improving. And at some point, hopefully, the offshore drilling can pick up again, too. But 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.

Now 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. And so 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. And so we're seeing an increased use of that steel. So it's partially mitigating the higher cost of the tungsten. We're still going to use tungsten. We're still going to deliver matrix bits. And that affects everybody across the board, not just us. That's an industry-wide for all drill bit suppliers. But pleased to see that some of the customers are willing to use some of the steel body bits as well.

Your next question comes from the line of Jim Rollyson with Raymond James.

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 that 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. And right now, we think price recovery in completions is a big opportunity. And so the fact that the market is tight and essentially sold out of everything that 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 3 years. And 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. across -- we use Caterpillar engines across all of our drilling business and our completions business.

And so 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. So -- we do have access to get the equipment if we decide to add fleets, but 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 going to be demand for higher capacity next year, but we have yet to pull the trigger on that.

Makes sense. And then just as a follow-up, maybe any updates on your kind of turn well JV 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 I'd love to get an update.

Sure. I don't want to overspeak for what ADNOC's plans are over there. I will tell you, we continue to participate in the turn well 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 1 to evaluate what it takes to get to Phase 2. And that's probably about the most I can say at this point.

Your next question comes from the line of Alexa Brenno with Goldman Sachs.

We just wanted to ask a follow-up 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?

Yes. So I'll break it into drilling and completions. So when you look at the drilling rig business, we were getting price increases on the new agreements and contracts we are signing up in the second quarter on average in the 10% to 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. And the market is tight for rigs. The market is demanding increasing capacity with upgrades. And when we do those upgrades, that's even a higher day rate as well. And so 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 3 years. And 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. A lot of those frac fleets are older Tier 2 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 efficient use of -- cost-efficient use of fuel in those basins, and they're demanding more of that. And I suspect that what you'll see in the second half of this year is certain customers -- 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 some time in the future when companies are willing to add capacity, which we don't see yet.

Yes. I would add to that a little, especially within the completions market, as you go 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.

Your next question comes from the line of Eddie Kim with Barclays.

So you provided an updated guidance in mid-May, not long after first quarter results and actually surpassed those -- 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, strength in 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 rig count increase here in the past 2 months, and you sort of assume kind of a 6-month lag at least. So 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 so quickly and any bright spots in that business?

Yes. So 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 going to do. And it wasn't a week or so after that, that we got into more discussions with E&Ps about putting out drilling rigs at a faster pace. And so 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. And 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 and the rig count request from E&Ps came in even harder than what we thought. And that's why you saw the rig count moving up. Now 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. So that was already moving. But 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.

Now the rig count continuing to move up, we are going to see tighter completions going into Q3 and also Q4. But what you haven't really seen yet in the market is the real demand of adding 50 rigs into the market. And you're not going to see that demand on the completion side until later this year and into 2027, 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 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. But for now, we're just focused on the pricing recovery in completions.

Understood. That's very helpful color. 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?

Yes. There's no update to that. That's still our commitment, and we expect to do that.

Your next question comes from the line of Dan Kutz with Morgan Stanley.

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 yes, 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?

Yes, I agree with everything you said. Yes. I think 40% is typically the target that we're looking at. And I do think that as we look at 2027, 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 -- but yes, 40% is sort of the target that we're always kind of focused on through cycle.

Great. 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. Just looking back, I think when through the Pioneer acquisition, there was 8 Columbia rigs that came along with that. I saw a note that they were pad capable. So I thought they were decent quality, relatively somewhat newer rigs and Latin America overall, obviously, Argentina, but Latin America overall has been an area of strength. So just kind of trying to square the -- you guys disclosed Colombia revenue, so you could see that it kind of slid 2 years ago and then last year came down substantially. Were any of those rigs relocated to other regions? Were any of those rigs wrapped? Just anything that you could share on the history of that business up until the decision to exit that you guys disclosed yesterday?

Yes. Thanks. So 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 didn't find to be strategic for us. Columbia came along with the package with 8 drilling rigs, but these drilling rigs were the older SCR type. The capacity of the rigs was good at, in some cases, 1 million pounds, but they are SCR rigs. And we believe we work 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.

But there's been a shift in the market down there, just like in other markets to go to newer AC high-spec rigs. 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 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. And so with the change in the politics in the country, the overall drilling activity has just slowed down. And these being SCR rigs are just not the rigs that people want to work in that country or even some of the others. So unfortunately, that's just kind of the life cycle of that type of technology. And then you have the headwind of the change in the direction of the government and wanting to drill oil wells at the same time.

Yes. And 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. So 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. And as it's become less active for us, we just thought it was the right time to exit the market and run all that.

Yes. And 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.

Your next question comes from the line of Sean Mitchell with Daniel Energy Partners.

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.

Yes. Thanks, Sean. So while there's a big focus on what's happening in the oil basins with oil trading at the levels that's been trading over the last quarter and the strip at 70-plus 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. And so 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 will round us out as well. So 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.

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. And then the pricing recovery that we're getting in completions in the second quarter and 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. So 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 that we're in. So thank you.

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

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Ladies and gentlemen, thank you for standing by. My name is Abby, and I will be your conference operator today. At this time, I would like to welcome everyone to the Patterson-UTI First Quarter 2026 Earnings Conference Call [Operator Instructions]

And I would now like to turn the conference over to Michael Sabella, Vice President of Investor Relations. You may begin.

Thank you, operator. Good morning, and welcome to Patterson-UTI's earnings conference call to discuss our first quarter 2026 results.

With me today are Andy Hendricks, President and Chief Executive Officer; and Andy Smith, Chief Financial Officer. As a reminder, statements that are made in this conference call that refer to the company's or management's plans, intentions, targets, beliefs, expectations or predictions for the future are considered forward-looking statements. These forward-looking statements are subject to risks and uncertainties as disclosed in the company's SEC filings which could cause the company's actual results to differ materially.

The company takes no obligation to publicly update or revise any forward-looking statements. Statements made in this conference call include non-GAAP financial measures. The required reconciliations to GAAP financial measures are included on our website, patenergy.com and in the company's press release issued prior to this conference call.

I will now turn the call over to Andy Hendricks Patterson-UTI as Chief Executive Officer.

Thank you, Mike, and welcome to our first quarter earnings conference call. I'm going to begin by saying we're hiring.

Now let's get started. The first quarter of 2026 built on our momentum from 2025 with strong field execution, supported by our technology and digital offerings across our diversified drilling and completions businesses. Our team stayed focused on the same priorities that drove last year's results, staying close to customers, delivering high-quality services and products that help them operate efficiently and aligning CapEx and operating costs would be opportunities ahead. We are proud of our performance and believe our position across all our businesses will allow us to continue delivering strong cash returns across a range of market conditions.

The commodity outlook has shifted materially since the start of the year due to heightened geopolitical risk and oil supply disruptions in the Middle East, which will likely reshape global oil supply and demand balances for several years. These developments underscore the strategic importance of U.S. oil and natural gas production and reinforce the need for a diversified global energy supply base with U.S. shale production more critical than ever.

Over the past several years, even as expectations for U.S. shale activity have fluctuated, we have remained focused on operational excellence in our core businesses. We have consistently believed that excelling in our core operating businesses is critical to enhancing shareholder value regardless of the macro environment. Today, we are pleased with the efficiency of our operations and as U.S. shale activity inflects higher, we believe the decisions we have made position us to capture outsized value from a higher U.S. rig count.

As a predominantly shale services company, we will always evaluate opportunities to deploy capital and expand our exposure to other geographies and product lines. However, we will remain disciplined and focused on returns for any potential growth investment. Momentum appears to be shifting back toward U.S. land activity over the coming quarters. But our corporate priorities remain unchanged. We will continue investing in technology and equipment that differentiates our services and supports long-term free cash flow per share while maintaining capital discipline, balance sheet strength and consistent returns of capital to shareholders.

We are well positioned to execute on these priorities. From a macro perspective, the outlook is improving, though the pace of recovery remains somewhat difficult to predict. We believe the industry will need to increase drilling and completion activity just to maintain oil production. With oil prices now running significantly above the mid-December levels assumed in many customers' 2026 budgets. We are encouraged by the setup for higher U.S. drilling and completion demand.

Some customers have already started to make plans for higher activity levels later this quarter, and we are increasingly hear that the strip is likely to incentivize additional incremental oil-directed drilling and completion activity in the second half of this year. The current WTI strip exits 2027 at approximately $70 as those prices hold, higher activity into 2027 becomes more likely, as is typical, private customers are moving faster than the public.

Natural grass activity also appears likely to improve as newly commissioned LNG facilities drive higher export volumes. While some of the incremental demand may be met by additional pipeline capacity from the Permian Basin later in 2026, we believe additional drilling and completion activity in gas-focused basins will be needed to fully supply that growth.

As a result, we believe natural gas-directed drilling and completion activity is likely to increase in 2027. In our Drilling Services segment, we are very pleased with how the first quarter unfolded. Pricing remained steady, reflecting the value customers place on performance and reliability. In addition to the cost control programs we implemented towards the end of last year continued to gain traction and provide meaningful support to results. Because customer programs typically adjust with a lag to changes in commodity prices, activity for some customers in the first half of the year continues to reflect prior budget assumptions. We are seeing conditions improve, and we expect momentum to build through the quarter.

We expect our rig count will exit the second quarter above the quarterly average and near the high point so far for the year, around 92 to 95 rigs depending on the timing, positioning us well as we move into the second half. As E&Ps continue to drill deeper zones and extend lateral links, the importance of rig capability and contracted performance continues to grow. The number of the most capable rigs, those with the load-bearing capacity and pipe handling systems required for today's deeper and longer, more complex wells remains limited and driven by investments from the best-performing drilling contractors. With our in-house engineering expertise and disciplined approach to upgrades, we believe we are well positioned to gain share in this growing market in a capital-efficient manner.

As rigs become larger and more technical, we expect this to strengthen our competitive position and support higher returns over time. Our Completion Services segment delivered solid results for the quarter despite disruption from a January winter storm that effectively paused the completions business for 5 days. Excluding that impact, our frac operations ran near capacity with our natural gas-powered assets near fully utilized.

Demand for completion service is improving, particularly in the back half of 2026. And we are in discussions with customers on higher pricing to more appropriately reflect rising demand and the high industry utilization. Available frac capacity across the industry is limited and a few fleets that could be reactivated are among the industry's oldest and least efficient. The current pricing reactivation does not seem economical, and pricing would need to rise meaningfully to incentivize incremental supply as demand increases.

While our completions business has nearly 250,000 cold stacked horsepower that could technically be reactivated. We have been clear that our priority is to invest in newer technologies that will drive long-term returns. Our cold stacked equipment represents the oldest diesel equipment in our fleet and reactivating a single feet would require more than $10 million investment. While the equipment could likely find work in the current market, the long-term return potential remains uncertain, and we are not prioritizing investment in these older assets.

Over the past several years, we have high-graded our fleet by investing in newer natural gas-powered technologies that we believe will remain in demand and generate strong returns for years to come. We continue to expect our nameplate horsepower to decline this year as we execute this high-grading strategy.

Over the past several years, the frac industry has seen consolidation and bifurcation of equipment quality and efficiency. Lower tier pricing has constrained cash generation for smaller peers, limiting their access to capital and slowing investment in new technology. This dynamic continues to widen the gap between the industry leaders and the broader peer group, supporting a more rational and stable market with structurally higher returns over time. We expect our nameplate horsepower to continue to decline. We are directing capital towards expanding our Emerald fleet of 100% natural gas-powered assets.

By year-end, we expect more than 15% of our active horsepower to be powered entirely by natural gas with approximately 90% powered at least partially by natural gas. We believe we have one of the highest quality fleets in the industry, and this transition reflects our ongoing focus on improving operational performance. In our Drilling Products segment, the team delivered solid performance despite several industry headwinds. The conflict in the Middle East has increased risk in one of our key regions, which contributes roughly 10% to 15% and of segment revenue, primarily from Saudi Arabia.

Land activity in Saudi Arabia largely tracked expectations during the quarter, although activity in certain regions was impacted. On the cost side, we've experienced meaningful inflation in several key inputs, particularly the material tungsten, where prices are significantly higher than a year ago. In addition, our Middle East operations have seen higher logistics and personnel costs due to the ongoing conflict in the region. Even with these challenges, our Drilling Products business delivered only a modest decline in adjusted gross profit versus the fourth quarter, and we are actively pursuing additional actions to further mitigate these risks.

From a competitive standpoint, we are encouraged by our position. We are pleased with the team's performance, and we believe we have grown to record market share in several key markets, including Saudi Arabia. In the U.S., we also believe there's additional upside with several large customers. Overall, our teams executed at a high level in the first quarter, maintaining a disciplined focus on service differentiation capital allocation and cost control as we navigated a demand environment shaped by customer budgets built on a crude oil price deck well below the current strip. We believe the indicators increasingly point to a period of higher commodity prices.

Based on our customer conversations, we expect this to drive an increase in U.S. shale activity starting later in the second quarter and continuing into the second half of the year. Even if oil prices moderate somewhat from current levels, we would still expect upside versus today's activity. As we approach an inflection in U.S. activity, it is worth briefly reflecting on the strategy we have followed in the past few years.

While we continue to evaluate opportunities to expand beyond our core markets, our priority will always be return on capital driven, and we have yet to find compelling opportunities that have cleared our investment threshold. We remain focused on strengthening our competitive position in our core businesses and improving efficiency. Operationally and financially. As we've always said, we believe disciplined capital allocation and continuous improvement in our existing businesses are important ways to enhance shareholder value. With activity now inflecting higher, the decisions we have made in the past several years position us to deliver improved performance going forward. We are pleased with where the company stands today and are confident in our ability to continue delivering strong cash returns to shareholders.

I'll now turn it over to Andy Smith, who will review the financial results for the quarter.

Thanks, Andy. Total reported revenue for the quarter was $1.117 billion. We reported a net loss attributable to common shareholders of $25 million or $0.06 per share. Adjusted EBITDA for the quarter totaled $205 million, which included $3 million in early contract termination revenue in the Drilling Services segment.

Our weighted average share count was 380 million shares during Q1. As expected, seasonal working capital headwinds impacted free cash flow in the first quarter. Given the timing and variability of these items throughout the year, we view full year free cash flow as the most meaningful measure of performance with working capital turning into a tailwind in the second half.

In our Drilling Services segment, first quarter revenue was $352 million and adjusted gross profit was $134 million. Revenue and adjusted gross profit included the previously mentioned $3 million of early contract termination payments. In U.S. contract drilling, we totaled 8,301 operating days in the quarter, with an average operating rig count of 92 rigs. Excluding early termination revenue, pricing was relatively steady versus the fourth quarter, and we continue to see benefits from the cost reduction actions implemented late last year.

For the second quarter in Drilling Services, we expect our rig count to average around 90 rigs, and we expect to exit the quarter above the average as we reactivate rigs in the back half of the quarter. We expect adjusted gross profit in the Drilling Services segment to be approximately $130 million, our guidance includes $5 million of rig reactivation and mobilization costs and assumes minimal second quarter revenue contribution from those reactivation.

In our Completion Services segment, first quarter revenue was $680 million and adjusted gross profit was $98 million. Results reflected the impact of roughly 5 days of winter storm impact in January. Excluding that disruption, our frac calendars were essentially full with limited spare capacity to increase activity at an extremely efficient calendar. For the second quarter, we expect Completion Services adjusted gross profit to be approximately $105 million, with near full utilization of our active assets.

First quarter Drilling Products revenue was $80 million and adjusted gross profit was $33 million. Results reflected disruption in the Middle East related to the ongoing conflict and some cost inflation. For the second quarter, we expect Drilling Products adjusted gross profit to decline slightly driven by lower profitability in our international business, particularly in the Middle East and the normal impact of spring breakup in Canada.

Other revenue was $6 million for the quarter with adjusted gross profit of $3 million. For the second quarter, we expect other adjusted gross profit to be approximately $5 million. General and administrative expenses in the first quarter were $69 million. For the second quarter, we expect G&A to be approximately $67 million. On a consolidated basis in the first quarter, depreciation, depletion, amortization and impairment expense totaled $218 million. For the second quarter, we expect it to be approximately $220 million. During the first quarter, total CapEx was $117 million, including $54 million in drilling services, $45 million in completion services, $16 million in drilling products and $1 million in other in corporate.

We ended the first quarter with $337 million of cash on hand and nothing drawn on our $500 million revolving credit facility. We have no senior note maturities until 2028. Our Board has approved a quarterly dividend of $0.10 per share payable June 15 to shareholders of record as of June 1.

I'll now turn it back to Andy Hendricks for closing remarks.

Thanks, Andy. I want to close the call with some additional comments on our company and the industry. The commodity outlook has shifted meaningfully since the start of the year with both current and future oil prices now well above the assumptions embedded in our customers' initial 2026 budgets. While many customers remain cautious in the near term, we are seeing a clear change in market tone, including more discussions around rig reactivations, stronger completion demand and improving pricing across our businesses.

Taken together, we have much more clarity on the market direction and these dynamics point to a more constructive environment for activity and profitability. For Patterson-UTI, even as we expect industry drilling and completion activity to inflect higher, we will continue to invest in our strategic initiatives to improve returns. In completions, we will continue to favor technology investments over investing in our older cold stacked equipment and investing at a measured pace into new assets that should generate stronger returns over multiple years.

In drilling, we are executing a disciplined cadence of structural upgrades to support deeper wells and longer laterals, consistent with where customer demand is trending. Digital and AI investments remains central to our strategy and are embedded across all of our operations. And with the changing market sentiment, we believe that technology upgrades will be well supported through favorable contractual structures to support accretive returns.

Finally, while the macro environment has changed, our corporate priorities have not, we remain focused on generating durable returns and sustainable free cash flow through the cycle while returning capital to shareholders. Our balance sheet remains strong, and we expect to deliver another solid year of free cash flow in 2026. As we evaluate opportunities to deploy capital, we will remain disciplined and prioritize investments that offer the highest return potential.

With that, I'd like to thank the men and women of Patterson-UTI, who work hard every day to help provide energy to the world. Avi, could you please open the lines for the questions?

[Operator Instructions] And our first question comes from the line of Saurabh Pant with Bank of America.

Andy I think your inbox is going to be full of resumes by the end of the day after listening to your first opening statement. But I guess, Andy, what I was getting at is, clearly, it sounds like the initial leg of the upside is being driven by the private completion of [indiscernible] Like if the rate that the cycle begins. But already, we are talking about parisensing. We are pretty much sold out on our, Halliburton said the same day -- same thing, Liberty kind of saying the same thing, right? So -- how are the public, right? Maybe help us think about how are the public thinking about when they want to add activity, how much they want to add activity, if they want to add activity. right? And at that stage, what would the supply side of the acquisition look like, how much equipment, how much capacity we would have or not have on the sidelines ready to come back maybe both on the rig and the stack side, if you can talk to that.

Okay. Let me see where I can start. So to begin with, we're really excited about the opportunity to put drilling rigs back to work. And like I mentioned earlier, we think we'll be somewhere between 2 to 5 rigs as we exit the quarter based on timing of when things go out. That's going to lead to higher completions demand as everybody understands over time. The interesting challenge that we have in the industry, as we've said, we're sold out of our top-tier equipment. We're essentially sold out of everything that convert natural gas. And we certainly will see a demand for for more capacity as we move through the year. But before we start adding more capacity, we're going to be very focused on returns and trying to improve pricing where we can and we'll be continuing the discussions that we're already having with a number of our customers on what that pricing should look like given the tightness in the market and given the demand. And you'll see instances over time, potentially where there's some trading of customers within the market. And we're going to work on improving pricing, improving returns before we start adding capacity. I think that's really critically important, especially given how pricing and completions has been pushed down over the last couple of years. And so it's important for us, important for our shareholders for us to improve the returns where we can before we start bringing more capacity onto the market and the completion side.

Right. No, that makes a ton of sense, Andy, right? And I'm glad your peers are taking the same approach, right? We've got a fixed pricing first, and then we'll talk about bringing capacity. So that's Fantastic. And then my follow-up, Andy, is on just the way pricing would work right? On the rig side, there's a contract book you have over does the contract duration look like? How quickly can we expect higher pricing to show up in your numbers based on your contract book and the same thing on the frac side. How should we think about pricing reopeners 3 months, 6 months? Or are there still sufficient number of annual contracts where pricing would take time to reset?

Yes. I think the best way I can describe the pricing situation on the rig side is when we did the last quarterly conference call, we said leading edge was in kind of the low 30s, and that's been down from the mid- to low 30s. I think what we're seeing today is pricing that is starting to move up from the low 30s. I mean, I'm not ready to call mid- to low 30s, but it's definitely moving up from the low 30s at the leading edge with everything fully loaded on the drilling rig. And so we're excited about that. And -- the other piece is as we get these requests for these technology upgrades on the drilling rigs, be it structural, be it digital, that leads to an investment, and it's going to require a term contract.

And we're hearing favorable commentary from our customers that they're willing to do that as well. And so that will lock in those returns for the investments that we have to make. But we are seeing leading-edge pricing on drilling rigs starting to move up. On the frac side, we're in discussions with the customers today. We have anecdotal evidence out there where some of the customers have already given us 10% price increases. I think that's relatively small compared to how completions has been pushed down over the last couple of years. But I think that given the tightness in the market, certainly from our side and what we hear from competitors, that pricing will move up towards the end of this year throughout. It will move up steadily over the next months through the end of the year.

Got it. Got it. And just to clarify very quickly, a majority of your frac contracts are on 3 months, 6 months kind of pricing reopeners. Is that right?

It's a bit of a mix, and we have some spot work in the second quarter. We do have some contracts that are longer term where the pricing only resets every 6 months for some very large customers. And that's okay. We're happy to work for those customers and we've got some customers where you revisit it as frequently as every month. So we've got a mix.

And our next question comes from the line of Derek Podhaizer with Piper Sandler.

Maybe a first question on the rig supply. So I think on the website, you're at 88 rigs today, you're talking about upwards of adding 7 rigs by the end of the quarter. Just wanted to see how immaterial those expenses are to get those rigs back to work? And maybe how many more rigs would you have behind that that require real capital investments and all the upgrades you're talking about deeper wells, longer laterals I'm just trying to think through putting upward pressure on that low 30s day rate towards the mid-30s or even into the mid- to high 30s, like we saw last cycle, just thinking on a rig-by-rig basis and how the required capital cost would be to bring certain rigs maybe after these 7 or these 10? Just maybe some thoughts around that.

Sure. I think that to start with the regulator going back to work, they haven't it hasn't been too long ago that they were working, but there are some costs incurred to put them back to work. From an accounting standpoint, we even have to capitalize some of the mobilizations too. And we've got some rigs that are moving in different parts of the country. And so that puts us at around $5 million in CapEx just to get everything back to work and put a number of rigs out through the end of the second quarter and into the third. So it's just the way we account for it, but we also get revenue back from that, we get paid for the mobilization too, but it comes through the CapEx line as well. As we move forward through the year, for some of the structural upgrades, we think that we have a relatively low-cost solution for a number of our customers out there.

It could be in the range of just a few million dollars, and we can see paybacks in 1 year, 1.5 years on some of that depending on the day rates that we get, and we'll lock that into term contracts. And that will start to push the day rates higher. I've said this before a number of times when we get into the large structural upgrades that we do, the CapEx costs are significantly higher. When you look at the APEX-XC rigs that we have working in the field today, which went through a large upgrade process, those day rates are pushing $40,000 a day. And I think that in the market that we're in, we will be exceeding $40,000 a day towards the end of this year and early next year. With those types of large structural upgrades.

Got it. Okay. Great. That's super helpful. I guess, on the frac side, I know you've talked about that you're effectively sold out. It's going to take a lot to bring equipment off the fence just given its legacy diesel. And maybe talk to the white space in the calendar in 2Q. Has that been fully soaked up how is second half firming up as far as your current frac equipment. Just trying to think through what needs to happen on your current active fleet as far as white space being soaked up for the remainder of the calendar year. before you would consider adding incremental new builds or equipment into this market, understanding that's likely going to be next-gen 100% natural gas type of equipment?

Yes. This has been a very dynamic situation. So I can tell you as of last week, there was some white space in the calendar that I think a lot of people wouldn't have understood given commodity prices today. But as of 2 days ago, we've basically filled the majority of that white space. So hats off to the team in completions and working with the customers to fill that up. And we see for completions that the second quarter is really kind of a transitory quarter, not quite the inflection that we're seeing in drilling, but then that inflection and completion comes right after that. And we feel like as of today, that we're fully loaded in the third quarter.

So I'm really pleased with what the team is doing, how they're working with the customers, how they've loaded up the calendar in the second quarter, considering how the overall U.S. rig count has continued to come down. But we -- looking past the second quarter and into the third, without getting into numbers, we feel like we're fully loaded in the third quarter.

And our next question comes from the line of Jim Rollinson with Raymond James.

as you kind of look at this, you've been through a lot of cycles, seeing a lot of these inflections I'm curious not calling you all just experienced. Just I'm curious -- how are you thinking about this as we go through the next couple of years, you've been talking, among others about how tight the market is underlying in frac for a while beyond just the fleet count numbers and all that. And I'm curious how you think about of getting all your pricing back to kind of where you were 2, 3 years ago. And I'm also curious, given what you guys have been doing on the cost side over the last couple of years. How does that translate into margins relative to like right after next year, close your kind of low 20s EBITDA margins in completion services. I'm just trying to connect the dots here to see where we might think margins trend over the next couple of years?

Okay. So a few things on completions and how it's going to play out in terms of margins and what are we going to do based on the tightness in the market. what's important for us right now is to try to constructively work with our customer base to get the pricing back in line for where we are in the market. Like I've mentioned, we've been pushed down in the completions pricing for the last couple of years. And for the shareholders, we need to get the returns back to a reasonable level. And so while we're still generating good cash flow, there's still an opportunity to get the returns higher. And we want to do that before we start adding capacity.

Now at the same time, throughout this year, we've been adding the new Emerald pumps that are 100% natural gas burning pumps and really excited about the uptake in the market. These pumps are really spoken for with various customers even before they show up in our own inventory. And so it's been a measured pace to bring those out. And when we do bring those out, it starts to improve our pricing and returns as we introduce those into the various fleets. But we don't want to add significant capacity to the market until we can structurally really kind of try to move the pricing up back to where we think it needs to be to get our returns.

Now on the positive side, to be able to do this, as I've said, we also hear that a number of our competitors are near sold out too. And with all the consolidation we've seen in the completions market over the last 5 years, is just structurally in a better place. And so while we are still competitive, I think there's a measured level of discipline in that market, too. to try to improve that market for our shareholders before we start adding capacity.

Makes sense. And as I think about CapEx, you guys obviously set a budget at the beginning of the year, which was kind of implying a down year as we're all expecting and things have changed. I'm just curious how you think about incremental capital to the budget. It's obviously returns driven, but just the order of magnitude, so we can kind of think about that as this start to let the other direction?

Yes. Jim, this is Andy. I don't -- we're kind of, again, on the front edges of this, and certainly, the conditions -- the market conditions that we're in today with remarkably different than what we looked in during our budget cycle -- so we're looking at it. I don't really have anything to give you right now, but I will say that we're looking at places where we think there could be opportunity, an opportunity to maybe lean into what we think is going to be a pretty strong price environment.

And our next question comes from the line of Scott Gruber with Citigroup.

I want to stay on the frac pricing discussion kind of topic du jour here. I want to dig in a little deeper just because historically the frac pricing discussion was kind of a simple generalized one. But today, there's so much more differentiation in the fleet. It's really a stratified fleet. So a couple of questions just thinking through how pricing could evolve from here. I guess to set kind of an upside scenario it's probably not unreasonable to discuss today. But kind of ballpark, how much incremental pricing would you need to see on the direct drive an e-frac to support new builds that reflect fleet expansion and not just replacement.

I think when we look at how we're deploying the new Emerald direct drive systems for 100% natural gas into our existing fleet the economics for that are actually very good. And the way we're pricing those and bringing them in are very good. But it's equipment that we've had out there under contract or under agreements for the last year or so. that we really need to bring that up to a level overall.

So we need to get our average up. It's not really about what we're getting for the new technology that we're putting out there. I think that's working really well. And I think we're getting the returns that we want out of that. And I'm more concerned about what we're getting in the overall averages. And I think that we're entering a very tight market for completions. As I've said for a while and for a few quarters, we've been sold out of our everything that can burn natural gas. But overall, the industry is about to enter a very tight market for completions. And I think that bodes well for all of us trying to get our returns up to acceptable levels. And then we can look at starting to bring in capacity increases of new technology.

Yes. I think the only thing that I would add to that is kind of given where we are in the market right now and the premium that gas burning equipment gets today. I think we're seeing pricing improvement across the fleet, more so, obviously, on the gas burning stuff. And so as we look at that, combined with what is, we think, kind of a crystallizing version of the market over the next couple of years or at least more visibility than we've had historically. I think you don't have to see a huge amount of pricing to be able to justify some new builds into this type of a market, but you probably still need 5% to 10% additional.

That makes sense. I mean, that's why I was going next is that gap kind of between the Emerald kit and the dual fuel kit. I imagine there's a gap between Emerald and Tier 4 dual and a gap between Tier 4 and Tier 2 dual -- any color you can give on those gaps? And as pricing improves, do those gaps compress -- or do they kind of retain and everything kind of goes up because you have the diesel displacement rates kind of sustaining a different economic advantage across a different type of kit.

And you're correct. There is various levels of technology and there is a pricing differential between those levels of technology. But the market situation that we're about to go in over the next 6 months is a rising tide that's going to lift all these boats. This -- the differentiation is still going to be there. The differential in the price is still going to be there -- but overall pricing for all these levels of technology, I expect to move up.

Yes. And again, with the diesel gas spread, I think that while all pricing will move up, you may see the spread between the different levels of equipment widened just in terms of the cost differential.

Yes. So you could see like Care 4 dual rise at a greater rate than Tier 2 is what you're saying?

Potentially, yes.

And our next question comes from the line of Stephen Gengaro with Stifel.

So 2 for me and one is on the same pricing discussion. But when we think about sort of the way the pricing contracts behave, given your positive commentary -- would you expect to see a strong inflection point in margin in the third quarter for completions? Or do you think it's more kind of a smoother increase as you go through the next couple of quarters? How should we think about kind of when we see it on the income statement?

I think it's going to be more of a smoother increase in pricing, not just over the next 2 quarters but into '27 as well. And I think this is going to be based on like I said, constructive negotiations with our customers. We're going to have customers call that want to increase their capacity. We're going to have E&P's call that we don't maybe not working for today, and it's going to create no opportunities and it's going to create negotiations with this customer base in general as to where this equipment goes. And this is an interesting market for us, but it's one that we need to do the right thing for our shareholders and improve the returns. And I think it's a steady process to do this over multi-quarters.

Okay. That's helpful. And -- the other question I had was, when we think about on the drilling side and you talked about some of the performance-based and I guess, kind of packaging of products over between completions and drilling. How does that play out in a tighter market? Like does it -- is it better for you? Does it give you more opportunity? Do you think a tighter market helps that approach or hurts that approach? How should we think about that?

Yes. We've actually seen over the last couple of years since we introduced this, and this is our P10 Advantage offering that we have for the E&Ps across drilling and completions we've seen challenges because the market was getting softer. But I've actually been in discussions with some mid-tier operators who say, "Look, hey, we may kick off a program. And if we do, we'd like to discuss with you what you can do for us because for them at a mid-tier level, expanding their program, they don't necessarily have all the internal resources to do that. And if we can help them on the efficiencies across drilling and completions, that's a positive form.

So this will be a positive market for expanding that offering. I appreciate that you asked the question. because as some of these midsized E&Ps look to expand what they're doing, they're going to need help, and we are well positioned to help them out.

And our next question comes from the line of Arun Jerian with JPMorgan.

Andy, your prepared comments suggest that the rig count is going to be trending up 5 to 7 rigs as we think about in 2Q. I'd love to get a little bit of color on which U.S. shale basins, are you seeing that incremental demand in on the rig side?

Interestingly, Arun, it's -- we're seeing it across multiple basins. So it's not concentrated in any 1 particular basin. But we've got customers that are in multiple basins, looking at the economics that they have it's oil, it's gas, it's across the board. So it's broad, and that's actually quite encouraging that it's not concentrated into one basin. That means that there's further opportunities over the next few quarters and pass that to expand the rig count as operators continue to look at their economics.

Got it. Got it. And just maybe my follow-up. Andy, you closed your prepared remarks talking about evaluating opportunities to deploy capital. You talked a lot about the Emerald technology, the 100% natural gas burning engines. What are you -- in terms of what are you looking for at this point to add that, call it, incremental capacity, your nameplate is actually going down this year, as you mentioned, but what are you looking for in terms of market signals to maybe step up, I think the CapEx guide is around $500 million or less this year, but what are you looking for to start, call it, deploying some growth capital in terms of the business?

Yes, Arun, I appreciate the question because as everybody knows, we've been holding back some cash, looking for opportunity to deploy that cash, whether that was through increasing the dividend that we did here recently or buying back shares, which we did last year. And we've also looked at opportunities in M&A as well. But as this market improves, we now have even further options because with an increasing activity and the demand that we're seeing on technologies, whether it's on the completion side with Emerald 100% natural gas or it's on the drilling side with the APEX-XC+ rig that we have we've got to evaluate what that looks like from a return standpoint and what we think is the right answer for the shareholders as we start to deploy more capital.

And our next question comes from the line of Keith MacKey with RBC Capital Markets.

I think it's I think it's pretty rare to have -- to be talking about termination revenue and rig activation in maybe the same call. Can you just -- maybe, Andy, walk us through a little bit about those factors and maybe it's a timing issue on the termination? And then with the rig reactivations, what type of CapEx or OpEx do these rigs need to come back? Is it a matter of increasing specification requests by the -- on behalf of the operators? Or any color there would be appreciated.

Yes. This quarter, as everybody knows, has had a lot of moving parts to it. And we've had E&P customers that started off the year with a budget at a certain level based on commodity prices at a certain level. and still under a lot of pressure from investors to keep CapEx in line and not overspend their budgets. And so yes, we did have a -- we've got rigs come down. We've had termination payments. all in the same quarter that we're having discussions now to put rigs back to work.

So it's been quite the quarter to try to navigate how we're going to manage this and watch our cost base as well because that creates challenges as the rig count is coming down, and then we've got to put a rig count back up to work, and it's in basins across the U.S. We've got rigs moving between basins. And so there's a lot of things going on. in terms of the cost base to put the rigs back to work after they've come down.

In terms of overall numbers to put rigs back to work, if they've been working I'd say in the last year, then we're in probably a range of $2 million CapEx to put them back to work. But there's also -- there's -- there's certainly no upgrades that are less than $1 million in terms of technology. And we're getting requests for structural upgrades. We're getting requests for some digital solution upgrades. And -- it really depends on the customer, where they're working, what the objective is that they're drilling as to the capacity that they wanted to do. And so that could potentially drive some more capital spend but we're still evaluating that and just trying to make sure that we understand the market and that we work through those discussions with the customers because as we spend those kind of dollars on upgrades, then we certainly want a contract to cover that.

Yes. And just to clarify, all that, make sure that we understand the rigs that we're talking about in the second quarter, we even completed the $5 million of operating expenses to reactivate those rigs. That's OpEx. That's not CapEx. The CapEx is probably on the rigs that would go to work that those rigs maybe are a little further out and have it worked so recently.

Got it. I appreciate that color. Maybe just turning to inflation. I think that certainly is a concern. There's some obvious places where we might be seeing it. But what type of potential inflationary factors are you watching? And how much of that do you think you're able to mitigate.

Certainly, in a lot of areas, of course, diesel price is moving up. The 1 thing that I will say is there's plenty of sand in the Permian Basin. So we're not seeing any challenges around sand where we have a lot of completion activities today. in terms of the Permian. Maybe some of the smaller basins are starting to tighten up a little bit, but we expect that changes over time, too, and then we're accommodated there. And then on the drilling product side, it's dealing with some of the materials that we have.

Basically saying that tungsten prices are moving up significantly right now. We're not the only industry right now given what's happening in the world that requires Tungsten. And so we're seeing that move up. But we actually have ways to mitigate that. We use the tungsten in the matrix body bits if we start to produce more steel is steel body bits and we can mitigate the cost of the tungsten as well. So just a number of things going on, but there's ways that we can mitigate that. We if there are costs that are moving up that we need to pass through to the customers, this is absolutely the right market to be able to do that in. And so we'll be looking at that as well.

And your next question comes from the line of Doug Becker with Capital One.

Andy, just wanted to get a finer point on how many rigs will be reactivated with the $5 million in costs? And is there a line of sight to some term work? Or are you really just seeing the spot market pick up to the point that gives you the comfort to deploy that capital?

Yes. I would say right now, nothing at that level yet, but we are looking ahead to the year as to what the needs might be in the second half of this year. and going into early 2027 and having those discussions with customers. And we'll certainly give you more information at the next quarter -- but when we talk about $5 million, that also includes mobilization costs as well, not just what we do in the drilling rig. But the market is certainly moving in the right direction to allow us to do some potentially significant upgrades on technology and maybe even take some share as we do this and we're excited for the discussions that we're in, we're excited for the market and the changing conditions. I've been optimistic through the year as we've been managing the business, but I'm far more than optimistic at this point in the market for where it's going right now.

Yes, definitely make sure clarify that, that $5 million ties to that 92% to 95% [indiscernible] rate that we're talking about earlier.

Got it. No, that makes sense. And maybe just a housekeeping item. You mentioned that firm cost about 5 days on completion services. Just any EBITDA impact from there?

On the winter storm?

Yes.

It was about $9 million. That's what we saw. We had that included in our guidance when we gave it last quarter. We weren't quite as fine a point on it. We said 5% to 10%, but it ended up being at the high end of that range.

And our next question comes from the line of Eddie Kim with Barclays.

Just surprised that the overall U.S. land rig count is still roughly flat since the beginning of the Iran conflict about 2 months ago. even as oil prices have increased substantially over that time period. Does that sort of reflect customers being in wait and see mode before deciding to pull the trigger on increasing activity or more so maybe the lag between actually making that decision and actually standing up a rig. Just any color there? And -- but it does seem like based on your outlook and your commentary that the industry-wide rig count should start picking up here within a matter of weeks.

Yes, I'll start, and then Andy can jump in and give you some more color. But I mean, our customers, just like we did, we went through a budget cycle and sort of all of this kind of came on right after we've kind of made our plans for the year. And so to change those plans on a on a pretty quick time line without 100% surety where it was going to end up or how long it was going to last, would be pretty difficult, I think, to even ask of our customers. And so I'm not surprised kind of by the pace at which things have started to come back. But that's my take on it. I don't know, Andy, if you have something you want to add to that?

Yes. Eddy in the public data you can get on the rigs, what you can see is that some of the biggest E&P operators in the U.S. that you buy gas from really haven't changed their programs. They're just sticking to their programs right now throughout the year because that's when they've set their budgets on -- and I think that really will probably kind of stay that way. I think you'll see other publics, and I think you'll see private start to move quicker. And that's what you're seeing in our rig count projections right now. But these large E&Ps will relook at their budgets for 2027, and that's why I'm also encouraged for next year as well. So I think you're going to see some of -- you've got some public, you've got some mid-tier E&Ps, you've got some privates that are all starting to we think this year and with increasing rig count and increasing completion activity and then the very large E&Ps will kick in for '27.

That's very helpful color. And just as it relates to your rigs, you mentioned exiting this quarter about 92 to 95 rigs, seems like just based on your commentary that 2026 could almost look like a near image of 2025. At the beginning of last year, you guys were running about $15 million active rigs. Do you think that $105 million is achievable for you guys by the fourth quarter of this year? Or would that be too much of a stretch?

I think it's too early to tell or try to project exactly what our rig count number is going to be at the end of this year, but we are encouraged about the discussions that we're having that we will put up more rigs in the second half after the second quarter. So very happy to be working in this type of market versus dealing with for the last year or so.

And our next question comes from the line of Dan Kutz with Morgan Stanley.

So maybe one on the international businesses that you guys have, kind of looking past the near-term disruptions related to the comp -- have you had any customer conversations or inbound in other regions outside of the Middle East or even any conversations with customers there that could -- that indicates potential activity upside or any inbound on incremental demand for Patterson services and equipment, whether it's across the drilling more global kind of drilling products business or you have the Lat Am drilling footprint and the turn will JV in the UAE. But yes, just wondering if you could care any thoughts or views or conversations that you've had about potential incremental upside in the international space.

Yes, I'll give you some color on what we're seeing. So I'll start with the Middle East from Kuwait on down to Oman. That's where we have a really solid drilling products business. we did see onshore activity relatively steady in those markets, especially Saudi Arabia and the UAE. But offshore, they did shut down a lot of the activity kind of midway through this conflict. And so that's had an effect. Also, particularly in Saudi Arabia, our customer there was working through some of their inventory that they had still in their warehouses.

And I think that slowed product sales for everybody over there. And at some point, that will end and then product sales will start to move up. And so with the onshore activity steady, we think we have some interesting opportunities over there. We are seeing some higher costs on logistics to get products and materials into the Middle East, and we've certainly seen a slowdown in Kuwait as well.

So we'll just have to see how a lot of this plays out. Moving over to South America. We did ship 2 drilling rigs down to Argentina. We do expect over the next year to 2 years that in Argentina, the rig count continues to move up. We may get to participate more in that process. We'll see. It's too early to call anything out on that yet. -- but we're in a number of conversations in Argentina. And I'll just go ahead and mention Venezuela. Nobody's talked about Venezuela in a while. There is a number of interested parties looking at Venezuela to try to get in there and increase production, especially in the Orinoco belt for heavy oil. But these -- these discussions will take time. And I think that process will go very slow. But there are -- as I mentioned, there are a number of interested parties.

That's all really helpful. And then coming back to the U.S., not sure if something that you guys if this is something that you guys track or have noticed or heard folks talking about, but just figured given your kind of unique footprint at the top, both driller and frac service company. seen some indicating that DUC inventories are low, potentially even materially low. And obviously, that can influence the relative pace of drilling versus completions activity at least from your remarks so far, it seems like you see upside in both markets, but just wondering if lower inventories is just kind of structural and as efficiencies improve or if you think that there's a dynamic there that could influence the pace of drilling versus completions activity.

Sure. I think with the DUC inventory this year, what we've seen is that it's come down, and a lot of that has to -- it's just directly related to the rig count coming down. and the number of wells between the drilling rigs and the completion activity. But also with some of the smaller customers, what we've seen is that they've really kind of tried to pace themselves through the year, and I'm talking about starting off at the beginning of the year where they drilled some wells and then they were going to complete them later. And some of those customers have called us based on current economics and said, hey, we want to frac these wells sooner. And so where we could, we've tried to accommodate them. And that's also led to some better returns on some of that work that we've done when we pulled that work forward. And -- but I wouldn't say it's widespread yet so far. But now we're going into a period where the drilling rig count is going to start to move up. And we're going to see the DUC inventory start to move up until completion activity moves up. And with the tightness in the completion market, and there could be a period that we are increasing DUCs even more than normal until we do get more completion work out there.

So I think it's going to be very positive for completions in the second half of this year.

And our final question comes from the line of Donald Crist with Johnson Rice.

Andy, I just have 1 kind of macro question. Hearing from some really smart people around the world and given your contacts in the Middle East that worldwide supplies are dwindling and the dichotomy between the physical markets and the financial markets for oil are pretty significant. And with that background, we're hearing that the strip could increase pretty materially despite whether or not this war is over sooner rather than later. And I'm just curious as to your kind of macro view on oil and whether or not we ever go back to $65 or $70 oil or if we do stay higher at, call it, an $80-plus oil level for the coming years. I know that's kind of more philosophical, but just your thoughts.

Well, Don, I really appreciate that macro question, and I'll start by qualifying that I'm not a commodities trader, but there's some interesting things happening in the market. And before you get into the crude discussion, there's a real challenge in some of the refined products like jet fuel, kerosene, distillates where those commodities have been ramping up at a faster rate than crude oil. And so I think that commodity traders on the crude side are kind of watching how these product sides trade to try to determine what the real cost per barrel should be because there is starting to be this disconnect between what traders opinion are of what all should trade at versus where you can physically get oil today and where you can move it to.

So we still, of course, have a bottleneck of crude in terms of global production that's missing and that's going to have to get filled at some point or it's going to have to start moving again, and that will take months to work itself out. So I think where the strip trades today, looking forward, is -- seems to be more of a best guess versus what the material price of a barrel of oil really is. And it will be interesting to see how that shakes out over the next year.

Yes. We're hearing from some really smart people that the strip is probably not going back to the $70 level again. So we'll see. We'll watch it together. I appreciate the thoughts.

Sure. But I'm certainly encouraged by how our customer base is reacting and how they're discussing the forward strip and the fact that we can tell you today that we're putting drilling rigs out.

And our final question comes from the line of John Daniel with Daniel Energy Partners.

So I've got 3 questions, and you might have answered all of these. And so I apologize if you did. But from the supply chain perspective, Andy, specifically for drilling capital equipment, where are the longest lead times today? And do you see that being a limiting or delay in rig reactivations over the next several quarters?

So there are some long lead items, some are close to a year. But those are some specialty items for some very large upgrades. But that being said, we've already been placing some orders for some long lead items. So we keep some things moving within the existing budget. As we -- when we talk about our capital budget at the beginning of the year, we talked about it's not just maintenance. We've got technology upgrades built in.

So we try to stay in front of some of these long lead items. And I don't think the lead time really changes. They just are what they are on some of these long-lead components that we've got to have, and we keep those on order where it makes sense. That being said, there's some shorter lead items, too, around structural steel and things like that, that we can get in a relatively reasonable pace. I haven't heard anything from the teams and we've had a lot of discussions over the that gives me any concern that we're going to have trouble getting any of these types of items at the pace that we think we're going to need them. So I think we're going to be fine on the technology and structural upgrades that we could potentially do over the next year.

Okay. That's helpful. And then you touched on international, Argentina and Venezuela. I'm curious what -- how do the rig specs differ between those markets and what you're doing here in the states? And just any operational color there would be helpful.

Yes. The good news for Argentina Baker is that you can take a drilling rig from the U.S. and you can move it right down there and drill one of the horizontals that they want to drill. So that's an almost identical rig spec. When you get to Venezuela, you kind of have to break it up into which basin you're talking about. But if you're talking about the Orinoco basin in the heavy oil we were drilling those wells 20 years ago with 1,000 horsepower rigs. And so very easily, you can take the 1,500-horsepower rig out of the U.S. and put it in there, and it's going to do better than we did before 20 years ago. And you do have some deeper onshore plays where you need 2,000 or 3,000 horsepower. But I suspect that the focus in Venezuela is going to be on the heavy oil because of the refineries in the Gulf Coast. And you've got -- the rigs in the U.S. will easily go down there and work there.

Okay. And then final one, for the people of your employees that were in the Middle East, what percent of them left when the conflict started? And what percent have returned? And then just as the guy that kind of oversees all these people, like what's your -- how do you think about sending more people back? And when do you do that?

Yes. So first, I want to say, and they know who they are within the company, hats off to our enterprise response team. They were running a 24-hour operation to logistically check on everybody that we had from Kuwait all the way down to Oman. Make sure that people were okay, comfortable where they were, assistance to move them out where they needed to get moved out. And one of the bigger concern areas was we had a number of rotators working in the field in the UAE -- we had to get them out over land to Oman and then fly them out of Oman once the flights were working in a reasonable way.

At this point today, we've got really everybody back to where they are. And so it's relatively business as usual. I say relatively because we do have concerns -- but the people that we have over there are comfortable working over there. If they're not happy working over there, we've certainly got work for them here. As I mentioned, we're hiring. So we've got plenty of stuff going on.

But no, the people that we're happy to go back.

And that concludes our question-and-answer session. I will now turn the conference back over to Andy Hendricks for closing remarks.

Thanks, Abby. I just want to thank everybody that dialed in today for our conference call. It's exciting time in the industry where we are seeing this inflection and very happy to report this quarter that we're putting drilling rigs back to work and that we have a good line of sight on completions for the rest of the year to be relatively fully loaded out.

So thank you.

And ladies and gentlemen, this concludes today's call, and we thank you for your participation. You may now disconnect.

Thank you for standing by. My name is Phila, and I will be your conference operator today. At this time, I would like to welcome everyone to the Patterson-UTI Fourth Quarter 2025 Earnings Conference Call. [Operator Instructions]

Thank you. I would now like to turn the conference over to Mike Sabella, Vice President of Investor Relations. You may begin.

Thank you, operator. Good morning, and welcome to Patterson-UTI's earnings conference call to discuss our fourth quarter 2025 results. With me today are Andy Hendricks, President and Chief Executive Officer; and Andy Smith, Chief Financial Officer.

As a reminder, statements that are made in this conference call that refer to the company's or management's plans, intentions, targets, beliefs, expectations or predictions for the future are considered forward-looking statements. These forward-looking statements are subject to risks and uncertainties as disclosed in the company's SEC filings, which could cause the company's actual results to differ materially. The company takes no obligation to publicly update or revise any forward-looking statements.

Statements made in this conference call include non-GAAP financial measures. The required reconciliations to GAAP financial measures are included on our website at patenergy.com and in the company's press release issued prior to this conference call.

I will now turn the call over to Andy Hendricks, Patterson-UTI's Chief Executive Officer.

Thank you, and welcome to our fourth quarter earnings conference call. We closed 2025 with a strong fourth quarter, delivering steady results through what's typically a seasonally soft period. Our teams remain highly disciplined with strong operational execution in the field and a focus on cost controls. We are pleased with the performance across all our businesses during 2025, particularly given the challenging commodity environment we faced throughout the year.

Patterson-UTI once again demonstrated its ability to generate strong free cash flow, delivering $416 million in adjusted free cash flow in 2025. Notably, the fourth quarter marked our highest adjusted free cash flow quarter since we completed our strategic transformation in 2023. This achievement highlights our ability to adapt to changing market conditions and underscores the effectiveness of our teams in maximizing our potential throughout all phases in the cycle. We are showing greater resilience to market fluctuations as we use our technology edge to deliver operational excellence.

I'd like to extend my sincere appreciation to all our employees for their hard work and dedication throughout 2025. Your efforts were instrumental in our success, and we look forward to moving Patterson-UTI forward again in 2026.

The industry overcame numerous challenges in 2025, including an increase in OPEC+ supply and ongoing macroeconomic uncertainties. Despite these pressures, the oil market has remained resilient with crude prices today at a similar level to those on our last quarterly earnings call. Although commodity prices remain unpredictable, in any scenario, at Patterson-UTI, we will remain committed to our core principles: delivering safe and efficient execution for our customers, investing capital responsibly in differentiated technologies and maximizing returns while generating substantial adjusted free cash flow for our investors.

Our free cash flow profile continues to be robust, which gives us confidence to increase our quarterly dividend by 25% to $0.10 per share in the first quarter. We are confident that our free cash flow will exceed our dividend commitments, providing the opportunity for additional share repurchases or other investments aimed at creating further shareholder value.

From a macro perspective, uncertainties remain regarding the sustainability of U.S. oil production at the current pace of activity. Recent data suggests that reduced drilling and completion programs in 2025 are beginning to impact production figures. The industry is likely approaching a point where we'll need to decide between declining production volumes or increased drilling activity to maintain production trends.

Although there may be a moderate decrease in U.S. oil activity in the near term, we do not believe that the industry can continue operating at lower drilling levels without causing a more significant impact to production than what has been seen so far.

We remain optimistic about the long-term prospects for natural gas, and we anticipate that a multiyear increase in drilling and completion activity will be needed to meet future demand. While there have been some incremental increases in natural gas-focused activity and natural gas prices have rebounded sharply due to winter weather demand, we expect most large customers will wait for clear commodity price signals after peak winter demand before making changes to their plans. As physical demand for natural gas for both LNG and power generation grows, we expect to see additional demand for our services in the second half of 2026.

In response to the macro environment, we have reduced our gross CapEx budget by around 15% to roughly $500 million in 2026. After accounting for the expected proceeds from a typical cadence of asset sales during 2026, we continue to expect that our CapEx net of asset sales will be below $500 million this year.

We have made significant progress in lowering our unit level maintenance CapEx requirements. We continue to successfully implement new digital processes that improve preventive maintenance, high grade our asset base with new technologies and consolidate facilities as we move further through the integration process of our businesses.

Importantly, our 2026 CapEx budget reflects funding for high-return projects that will further enhance the quality of our operations and ensure we are well positioned with new technology that supports the next leg of customer demand. While we are substantially reducing our overall CapEx budget, we fully expect to exit 2026 with a more advanced and higher-quality asset base than at the start of the year.

During the fourth quarter, our U.S. Contract Drilling Business saw a relatively steady activity and pricing compared to late third quarter levels, and this stability continued into 2026. Our focus remains on identifying investing in assets and technologies that bifurcate drilling performance and create unique value for both our customers and investors.

Of note, we have seen increasing acceptance of performance-based commercial agreements, and this shift reflects growing customer interest in partnering with service providers who can enhance operational efficiency. Our ability to deploy advanced APEX rig technology that enables faster drilling of more complicated wells is resonating with our customers.

We are also seeing strong results from the broader adoption of our drilling automation packages. Nearly all of our rigs are now equipped with our proprietary Cortex automation applications, and demand remains high as we continue to develop new software applications to further improve drilling operations, with many of these in partnership with our customers.

Looking ahead, the evolving shale landscape is characterized by more complex well designs, requiring rigs with increased load capacity that control deeper geological formations as well as longer and more complex laterals into higher pressure zones. Future demand will increasingly favor differentiated rig technology, positioning Patterson-UTI and our fleet of advanced assets and technology with a distinct advantage over much of the competition.

The benefit of this differentiation has already been reflected in our ability to sustain margins at higher levels than we have seen during periods of activity moderation in prior cycles. As the market continues to favor high-quality drilling solutions, we anticipate that our advanced technology will further strengthen our position as we aim to sustain pricing and margins as customers seek out the best available drilling contractor to meet their increasingly complex needs.

In Argentina, we are excited with our recent agreement to lease 2 high-spec rigs for work in the Vaca Muerta field. The multiyear agreement is a capital-efficient way for us to put idle assets in the U.S. to work internationally. The opportunity in Argentina is one of the most promising that we see to put our idle assets to work globally, and our fleet of rigs in the U.S. are well suited to meet the region's growing demand for unconventional drilling over the next few years.

The expansion also complements our established position in drilling products, including Ulterra drill bits in Argentina. We believe that further planned increases in drilling activity in Argentina will reduce the available supply in the U.S.

Our Completion Services segment delivered strong results in the fourth quarter. Segment adjusted EBITDA for the second half of the year was higher than the first half, reflecting the quality of our operations and the steps we have taken over the past year to add new technology to our portfolio, streamline operations through our digital platform and improve our cost structure. Our team effectively managed holiday downtime across several of our larger fleets, successfully securing work to maintain high utilization. Pricing and activity remained steady compared to the third quarter.

Our frac assets remain highly utilized in the first quarter with almost 2.5 million horsepower either deployed in the field or in normal maintenance cycles. We have very little spare capacity, and our idle horsepower consists entirely of older diesel equipment that is not part of our long-term strategy. As we direct our capital towards high grading our asset base with additional Emerald 100% natural gas equipment, we are likely to have fewer fleets in operation as we continue to idle lower-quality diesel assets and focus on the premium market.

Our equipment that can utilize natural gases and fuel is fully utilized. Our asset base will continue to reflect this high-grading strategy. Our nameplate horsepower totaled 2.7 million at the close of 2025, which is down more than 600,000 horsepower from 2 years. And we are likely to see a further reduction this year.

Within our Completion Services segment, we continue to see growth opportunities in high-end natural gas powered frac equipment in our industry-leading and proprietary digital completions platform, which we call eos. Our Emerald 100% natural gas-powered footprint will grow again in 2026. And by the end of the year, we expect that more than 85% of our assets will be capable of using natural gas as a fuel in some capacity.

We believe our asset quality is among the best in the industry and the strong demand and returns for our high-end equipment position us to maintain resilient margins across our higher technology assets. We will reduce capacity of our older assets, and we believe the industry is also doing the same.

Although public estimates of U.S. industry fleet count shows a decline, the total horsepower deployed has not declined and has remained roughly consistent. The frac industry is evolving towards larger fleets at the well site, a trend that we believe is being overlooked by public industry data on the number of active fleets, resulting in the frac fleet count becoming less of a reliable metric to determine industry completion activity.

At the same time, the significant increase in pumping hours per day over the past several years has likely run its course. Some providers are encountering technical limitations on most of their fleets with our average frac fleet now pumping over 22 hours per day. With continuous pumping, our team has been leaders in executing on the growing trend to achieve 24-hour operations.

But continuous pumping fleets require significantly more equipment on location relative to a more normal operation, which increases the cost of continuous pumping and further restrict supply. We have successfully executed several continuous pumping jobs to date as customers are currently evaluating whether the incremental increase in uptime justifies the additional cost.

During the fourth quarter, we launched our proprietary eos Completions Digital Platform. eos connects our customers directly with their live field data, allowing the customer and our completions teams to improve real-time decision-making on the same platform. Our customers can eliminate the need for multiple third-party software platforms in their data flow and improve their overall data quality with a direct link to our digital performance center.

The eos platform is hardware-agnostic, allowing our completions data and also third-party data sets to be delivered to customers on the same platform with no delays. The eos platform includes our advanced Vertex automated frac controls, which to date have been deployed across most of our active fleets and regardless of frac power type. eos also supports our other services such as waterline, pumpdown, natural gas delivery and proppant logistics.

This takes our completions segment to the ultimate goal of push button frac, and soon, with closed-loop decision-making, which will deliver more consistent completions to our customers and over time lower our operating and equipment maintenance costs. We have revenue-generating agreements in place now and are seeing increased customer interest for deploying this platform.

Our Drilling Products segment delivered another strong quarter in North America, Revenue per industry rig remained close to company record levels in both the U.S. and Canada, underscoring our robust market position in drill bits. Additionally, we are having continued success with new downhole tool product innovations helping us to maintain relative strength in these markets.

Internationally, revenue experienced a slight decline from the third quarter, primarily on lower-than-expected revenue in the Middle East. However, we achieved revenue growth in several important regions, including Latin America and Asia Pacific. Looking ahead, we remain optimistic that the international outlook for our Drilling Products segment will improve as we progress through 2026. We have opened a new manufacturing facility in Saudi Arabia that are now manufacturing drill bits in country, which should give us an advantage as growth resumes in the Middle East.

Patterson-UTI continues to look to extend our leadership position while the U.S. shale industry undergoes significant changes. The company's operational excellence within both the drilling and completions segments has provided a competitive advantage, enabling effective navigation through the current commodity environment. Target investments across businesses will remain a potential focus. These strategic efforts are evident in the company's ability to generate robust free cash flow and maintain relatively resilient margins, even through periods of activity moderation.

Even with ongoing commodity volatility, we are well positioned to deploy capital in ways that add value for shareholders, including through additional shareholder returns. We will continue to be flexible with capital deployment and evaluate a mix of dividends, buybacks and other potential growth opportunities.

I'll now turn it over to Andy Smith, who will review the financial results for the quarter.

Thanks, Andy. Total reported revenue for the quarter was $1.151 billion. We reported a net loss attributable to common shareholders of $9 million or $0.02 per share. Adjusted EBITDA for the quarter totaled $221 million. Our weighted average share count was 379 million shares during Q4.

During 2025, we once again showed the cash generation potential of our company with adjusted free cash flow totaling $416 million for the year. As expected, the fourth quarter was the strongest cash-generating quarter of the year by a wide margin.

It is important to remember that given the timing of some working capital items, including significant customer prepayments that we typically receive in the fourth quarter for work to be performed during the first half of the following year, it is far more meaningful to analyze our free cash flow on a full year basis as the quarterly results can show greater variability.

For year-over-year comparisons, the customer prepayments we received in the fourth quarter of 2025 were roughly $15 million higher than those we received in the fourth quarter of 2024.

Before we get into the segment discussion and the outlook, I want to give an update regarding the impact from severe winter weather that has already occurred during the first quarter. The January 2026 winter storm disrupted large portions of our operations for several days, and we believe the full impact of the disruption will have a negative impact on our first quarter adjusted gross profit, particularly in our Completion Services segment. The estimated impact of this event is included in the quarterly guidance numbers we will discuss.

In our Drilling Services segment, fourth quarter revenue was $361 million and adjusted gross profit totaled $132 million. In U.S. Contract Drilling, we totaled 8,596 operating days for an average operating rig count of 93 rigs. Our successful cost reduction measures mostly offset the revenue decrease during the quarter. For the first quarter in Drilling Services, we expect our average rig count to be in the low to mid-90s. We expect adjusted gross profit within the Drilling Services segment will decline by less than 5% from the fourth quarter.

Revenue for the fourth quarter in our Completion Services segment totaled $702 million with an adjusted gross profit of $111 million. Activity and pricing were mostly steady compared to the third quarter with minimal seasonal downtime. For the first quarter, we expect Completion Services adjusted gross profit to be approximately $95 million with slightly lower activity given the impact of the first quarter winter weather.

Fourth quarter Drilling Products revenue totaled $84 million with an adjusted gross profit of $34 million. Revenue per industry rig in the U.S. remain near company record levels. We saw a decrease in revenue from our international operations, mostly from lower-than-expected sales in the Middle East, although we did see revenue growth in several markets, including Latin America and Asia Pacific.

For the first quarter, we expect Drilling Products adjusted gross profit to improve slightly with slightly lower revenue in the U.S. offset by an increase in activity and revenue from our international business. As we move through 2026, we expect to see an improvement in international revenue in the Drilling Products segment as activity improves, primarily in Saudi Arabia. We also expect to see growth in downhole tools and new product development.

Other revenue totaled $5 million for the quarter with $1 million in adjusted gross profit. We expect Other adjusted gross profit in the first quarter to be steady compared to the fourth quarter.

Selling, general and administrative expenses in the fourth quarter were $62 million. For Q1, we expect SG&A expenses will be approximately $65 million. On a consolidated basis for the fourth quarter, depreciation, depletion, amortization and impairment expense totaled $221 million. And for the first quarter, we expect it will be approximately $225 million.

During Q4, total CapEx was $139 million, including $61 million in Drilling Services, $59 million in Completion Services, $15 million in Drilling Products and $4 million in Other and corporate. For 2026, we expect gross CapEx to approximate $500 million and to be below $500 million net of asset sales. We expect CapEx will be weighted towards the first half of the year as we bring in new technologies into both the Drilling and Completion Services businesses.

We closed Q4 with $421 million in cash on hand and we did not have anything drawn on our $500 million revolving credit facility. We do not have any senior note maturities until 2028.

During 2025, we returned $119 million to shareholders through dividends and share repurchases. Since the start of 2024, we have returned roughly 2/3 of our adjusted free cash flow to shareholders through dividends and buybacks, and we remain committed to returning at least 50% of our adjusted free cash flow to shareholders. Our Board has approved a 25% increase in our quarterly dividend to $0.10 per share, payable on March 16 to holders of record as of March 2.

I'll now turn it back to Andy Hendricks for closing remarks.

Thanks, Andy. I want to close the call with some comments on our company and the industry. I'm very pleased with how our segments performed in the fourth quarter, where we were able to show improvements in controlling costs and keeping them in line with the activity changes. This is a testament to focusing on what we do best: providing products and services to efficiently drill and complete wells. The result is that we were able to generate strong free cash flow to close out 2025.

As well, I'm pleased to see the stable activity continue into the first quarter of 2026. The outlook for 2026 has the challenge of some commodity uncertainty. With oil prices trading near $60 per barrel, my expectation is that activity in oil basins remains relatively steady from where we are today. Oil markets have remained resilient, looking ahead to continuing economic growth, along with some geopolitical unrest. Gas markets remain steady and have the potential for some activity upside later in the year. It's early to predict how 2026 will play out, but I'm encouraged by our current activity levels so far in the first quarter.

We continue to invest in new technology in both drilling and completions, where we are seeing strong returns on our capital investments. In Drilling Services, we are being asked for new Cortex automation applications by our customers, along with upgrades to our APEX rig structures to drill deeper geological horizons and longer laterals. In Completion Services, we will continue to add new Emerald 100% natural gas fuel technology to our fleet and continue the rollout of the eos platform, which includes the Vertex automated frac system.

In Saudi Arabia, Ulterra manufactured their first drill bit in-country in December. And this new manufacturing capacity, combined with our strong performance in the region and the planned increase in drilling in Saudi Arabia, gives our drill bit business some international upside this year. These technology and manufacturing investments allow us to continue to differentiate ourselves versus our competitors and maximize the margins we were able to earn. And we're doing all of this while reducing our overall capital expenditures in 2026.

We remain focused on generating strong free cash flow for our shareholders and, over the last year, we have a higher level of cash than what is currently required to sustain our business. Given our cash generation potential, I am pleased that our Board has approved a 25% increase in our quarterly dividend as part of our overall commitment to return cash to shareholders. With our current cash position and after capital expenditures, we will continue to repurchase shares in the market where it makes sense and also continue to look for growth opportunities.

Once again, I'd like to thank the men and women of Patterson-UTI Energy for their outstanding performance in 2025 and for helping to responsibly provide energy to the world. Thank you for joining us today for our Q4 2025 earnings call.

We'd now like to open the lines for Q&A.

[Operator Instructions] Your first question comes from the line of Scott Gruber with Citi.

Andy, I appreciate all the color on the dynamics at play in the frac market today. How do you see the U.S. frac supply/demand balance today given the enlargement of the average fleet? It's grown a long way here over the last couple of years. And do you have a sense of roughly fleet utilization for the market? And can attrition alone drive us back to a relatively tight market balance in the not-too-distant future?

Yes. In terms of fleet activity, it's really an interesting situation. We've been trying to explain for a while now the dynamics in the data that you're getting from various public sources. If you look at what we did across 2025 last year, public data is showing a reduction in our fleet count. But at the same time, the size of our fleet, the amount of horsepower on location has just been continuing to grow.

We're doing more simul-frac. We're doing more trimul-frac. And even on the same simul-frac, we're getting requests for higher rates and higher pressures. So that's causing us to put more equipment on location. When we do put more equipment on location, we certainly factor that into the pricing for the job. We're committing more assets so it costs the operator more, but they're getting a cost benefit. They've done their economic evaluation on what it takes to maximize production out of their wellbore and that's what they've determined. So in some ways, it's been a win-win.

But the challenge for people trying to understand the business is that while the fleet count looks like it's going down, we've actually remained really relatively steady in the amount of horsepower that's been deployed. So we've been moving horsepower around to different places and growing the amount that we have on the well site. And I see that trend continuing at maybe a measured pace in 2026, but you see that trend continuing.

And what that means is it continues to reduce overall supply in the frac market. And all the equipment that we have that can burn natural gas is certainly not working, and that has a cost benefit to operators when they convert natural gas. So that market still remains very tight because of the amount of horsepower growth on a per fleet basis.

I appreciate all that. And then I think your current tower business is looking at some opportunities to supply energy storage systems at data centers and other applications outside of oil and gas. Can you provide some color on that initiative?

Yes. We do have an electrical engineering division. It's called Current Power. And they've built and engineered very specific micro grids and they do battery storage for mainly our drilling rigs. There may be an opportunity in the future for them to do some measured type of storage for data centers, but that would be a pretty large-scale project even for us. There's some technology there that could be interesting, but I'd say it's very early to see if that pans out to anything.

Your next question comes from the line of Saurabh Pant with Bank of America.

Andy, maybe I'll just start with a bigger picture question. I think you were talking about increasing differentiation in your prepared remarks. And honestly, I see that in the kimberlite data as well, right? I think your performance, your value proposition seems to be improving in the eyes of the customers in both drilling and completion.

As I think about what it means for financial, right, it seems to me like the gap between the top 2, 3, call it, 4 players, including yourselves, and the other small medium-sized providers is actually increasing, right. So it should be good for your pricing power in the market. So maybe just talk to that dynamic a little bit, differentiation and pricing power and how pricing has held up a lot better.

Yes, I appreciate that question, and thanks for noticing some third-party data that shows that we continue to improve our operations. Really pleased with how the teams have improved execution over the years. And also, it gives us confidence to continue to fund them with capital for a new technology. And we do think that, that continues to differentiate us in the market, both on Drilling Services and Completion Services. So really pleased with the performance overall for the teams.

We're working for some of the biggest E&Ps in the U.S. in both drilling and completions. And it's the size and scale of the operations, the breadth of services that we can provide, the level of technology we can provide and the execution that we're providing in the field that's really driving all that. So it's not just one thing in particular but it's multiple factors, and just really pleased with how that's been working out.

In terms of pricing, one of the things that we've shown here over the last couple of years is even though you've seen especially in drilling a decline in the rig count, you haven't seen compression in margins like you've seen in previous years. And technology is a big part of that driver where we can differentiate certainly for much smaller companies. And it helps to really kind of shore up our ability to protect the pricing and margins where we can.

Our business is certainly still competitive in nature, especially in West Texas, where you're seeing a little bit more slowdown in the oil markets versus the gas market. So there's still competitive market out there. But really pleased with how we're performing in general and also very pleased at how well we've been able to keep the margins up relative to previous cycles.

No, that's fantastic, Andy. And then maybe just a quick follow-up on what Scott was asking on the supply/demand side of things. I know it's very early to ask about pricing power coming back to the market, but I know it will at some point, right? So in some ways, Andy, how should we think about how much incremental demand maybe on the rig side and on the frac side would it take for soft pricing power to come back to the industry? Now I don't know when it happens, but just some sense of what kind of demand pull we might need for that.

Yes. It's a really interesting situation, especially for us, where all of our equipment that can burn natural gas is out working today. And so if we see the activity increase in the natural gas basins towards the end of this year to supply both LNG demand initially and, over time, increasing power demand in the U.S., that draw on natural gas is going to cause an increase in activity in both drilling and completions. And on the completions side, we are essentially sold out of all of our equipment to convert natural gas.

And when you're working in those gas markets, the operators, the E&P certainly want to fuel that equipment with natural gas. And we would have to add to our asset base at that point and that's going to cause a significant inflection in pricing in that point. So my expectation is that once we see an activity increase in these gas basins, it's really going to drive an increase in the pricing on the completions as well because we're going to have to add assets to do that.

Got it. Right. No, I think things move pretty quickly on both sides, right? So we should not forget that. And a very quick follow-up for Andy, if you don't mind. Andy, you were talking about some weather impact on your first quarter guidance. Did you quantify the impact, if I missed that, if you have any color on how big that impact is.

We didn't quantify it, but it's in the range of $5 million to $10 million. It's included in our guidance. So it's certainly not incremental to anything. It's already included, but it's probably in the $5 million to $10 million range.

And your next question comes from the line of Jim Rollyson with Raymond James.

Andy, you kind of talked about the demand side with your technology and all the things you've been going through this kind of market over the last couple of years. One of the things that's really been pretty notable here over the last -- at least the back half of '25, if not longer, is what you guys have been doing on the cost side. It showed up really in Completion Services kind of first. It certainly showed up in Drilling Services this quarter.

Maybe just spend a minute on kind of what all you're doing to bring your cost structure down and kind of what inning you might be in just as we think about -- it may be a stable market, not that, that happens, but how margins proceed in both those businesses going forward.

Yes. So my hats off to the teams. They've really been digging in hard as to how we're spending every dollar out there both in OpEx and CapEx. And you look at things like maintenance CapEx, what are we spending our money on? Are there things that we can do to refurb versus buy new parts? Are there things that we can do to negotiate with some of our suppliers given the state of the market? There's just a number of efforts out there to try to rein that in.

I'll also say that the teams have worked to become more efficient so they can do more with the same amount of people and get more accomplished from a maintenance standpoint. So maintenance has been a big driver in the cost savings in both the Drilling Services and Completion Services segment, both OpEx and CapEx.

Yes, Jim, I would add to that. So yes, as Andy said, crew sizes particularly around in the Completion Services area as well as the support structure footprint, as we have consolidated these businesses over time, we've looked to co-locate where we can or slim down sort of our fixed asset footprint in terms of our support facilities.

And then on the SG&A side, as we've gone through and tried to integrate the back office even more, consolidate, centralize, it allows us to control some of those costs, get them out of the businesses and let them be managed, quite honestly, from the corporate side. So we turn the business units loose to sort of focus on their operations more so than kind of what they're doing on the back office side. So I would say all of those things have an effect, and we'll continue to do more on those. But yes, it's been a real focused effort over the last year or 2.

Yes. Well, it's been impressive. And then just as a follow-up, you kind of took upon this path of returning at least half your free cash flow a couple of years or so back. And you've obviously exceeded that number pretty candidly each year. You just raised the dividend by 25%. And I presume with all the things going on, your free cash flow conversion rate should probably be pretty stable at least.

Just curious, you didn't buy a whole lot of stock back in 4Q. And even with the dividend hike and kind of where numbers are, you have quite a bit of room to be able to buy back stock throughout 2026. Just maybe your philosophy on that given that your share price hasn't ripped but it's certainly improved a little bit from where it was at the bottom. So I'm just kind of curious the philosophy there.

This is Andy Smith. I would say that nothing has really changed philosophically for us, Jim. Look, it's pretty clear for those that have been following us for a while that we run this company to maximize free cash flow. And so as we look at anything on the capital allocation front, that's kind of our primary focus. Whether it's looking at reinvesting into our fleet, whether it's looking at buying back shares, whether it's looking at M&A, we kind of look at them all in terms of how much cash flow per share accretion can we get out of those opportunities.

And I would say in the fourth quarter, the reason there was a little bit of pause on the buyback was more about lumpiness of working capital and things like that, and it kind of came in late in the quarter. And so nothing really has changed. But we continue to look at all of our capital allocation priorities through that sort of free cash flow per share metric. And we ultimately think that in the end, that serves us pretty well and that's how we run the business.

So again, I wouldn't say to read too much into that. I don't think anything has really changed in terms of our philosophy.

Yes, I agree. I don't think anything has changed in how we look at that. But one thing, when you look at the bigger macro and you look at what's happening in the industry over the last couple of years, the market has softened over the last couple of years, but yet we're still generating strong free cash flow, that's our focus. And so that gave us the confidence to go ahead and just raise the dividend. Because here we are in a softer portion of the market but yet we're still producing strong free cash flow, and we still have forward visibility on that.

And your next question comes from the line of Derek Podhaizer with Piper.

I know you mentioned some of the comments around Argentina and setting some of your idle rigs down there. Maybe just give us a sense of you walk around the world, you're seeing all the unconventional development pickup. I think it's specifically about your turn well JV over in the UAE. What can we think about you guys explore these international regions, starting with Argentina, maybe UAE, anywhere else? Just some comments and thoughts around that.

Yes. We've looked at these markets for more than a decade to try to see where we can fit in and where it makes sense and where we can get decent earnings out of it. And these markets have various competitors, but they also have rig specifications that differ from the U.S. in a lot of markets. The interesting thing about Argentina, it's almost an identical rig specification to what we have here in the U.S. And so it's easy from a technology transfer and even a capital efficiency standpoint to say, okay, yes, we can move a drilling rig down in Argentina and work in that environment without big technical changes.

And so as the Vaca Muerta activity continues to grow in activity and they continue to use the available supply in Argentina, they're looking to the U.S. to bring rigs down from various drilling contractors. This agreement worked out for us to partner up with a local supplier who, has a good reputation in the region and is working for some of the biggest E&Ps there. And so this worked out really well for us to be able to get to an agreement with them to provide them with a couple of drilling rigs to go down there.

And while it's only 2 rigs leaving the U.S. market, I think everybody who's been following Argentina knows that you've got operators that are over there currently. You've got U.S. operators that are looking to move into Argentina. And activity will continue to grow in Argentina over the next 5 years and those rigs are going to come out of the U.S and, over time, that's going to reduce the U.S. rig supply. And so we'll continue discussions with companies that are currently there and companies that are going down there, and we'll provide rigs where it makes sense for us to provide rigs.

Got it. That makes sense. Very helpful color. And then just thinking about the frac side of things, I appreciate the comments quantifying some of the impact here in the first quarter due to winter. But maybe you can take a chance on walking through second quarter, third quarter, what you see out there, your customer conversations. Will we get a snap back in utilization? Just trying to think through the different crosswinds around pricing resetting. Just maybe some help understanding, as we move through the year, what we could see out of the completion side of the business.

Yes. We were really pleased to see that the first quarter was still relatively steady. In the fourth quarter, we were able to exceed expectations in overall activity relative to how a fourth quarter normally plays out. And then relatively steady into the first quarter, the weather issues aside that everybody went through. As we go through the year, if the commodity prices stay in the $60 range, my expectation is that the oil markets stay relatively steady.

I think that as a lot of E&Ps were working on their budgets in December, you had oil commodity prices at various levels in December, which kind of made it challenging for a number of our customers to decide what their activity is going to be during the year. But we've seen more resilience, I think, than many of us have expected. And if that resilience persists and oil stays in that upper 50% to 60% range, then the market likely to remain relatively steady.

And your next question comes from the line of Stephen Gengaro with Stifel.

I guess, on the frac side, I was just curious what your view is on two things. One is if you think we'll see further consolidation in the business. And maybe tied to that, do you feel like over the last, I don't know, 6 months or a year that the behavior of the industry and the peers has been fairly good? Or do you still see some people who are underpricing the market?

So I think the frac market has been evolving from a technology standpoint, and I think that you're seeing differentiation with the top 3 or 4 players versus others. And I think that technology differentiation continues for the next few years. You can certainly see it in where we're investing dollars. So we continue to invest in the 100% natural gas Emerald fleets that we have deployed. There's still very strong demand for equipment that can burn 100% natural gas, and we're going to continue to do that. And so we're going to continue to grow our capacity of that high-end frac equipment probably higher than some of the others are deploying today. So we see that.

And then you see digital. Digital still has a lot of evolution to go in the frac space. And so we announced, it was a big event at an industry conference this week in the Houston area where our teams rolled out the new eos platform for digital. It allows our customers to be able to aggregate all their data without various third parties, put it all in one place, visualize it, work with it, do what they need to do with it. But that platform is not just about data aggregation and moving data. It's also about the controls and working with the control systems that we have, which are proprietary to our equipment.

And we have the Vertex automation on the frac. And so it's these kind of investments in the higher-end technology on the equipment side, but also the investments on the digital, which will allow us to continue to differentiate. And I think that it's going to roll up to the top 4, maybe just 3 players that can do that and differentiate from the others.

Okay. That's helpful. And just the other quick question. Just on the rig side just on the North American market, do you feel like pricing has stabilized?

I think where we are today, you've got some available rigs in West Texas. It's still a price competitive environment out there. But I'm pleased with our ability to protect our pricing and margins the way we have. And we'll just have to see how it plays out. I think where the commodity price lands as an average for the year will be a lot to [ drive ] that. So if it stays upper 50s to 60s, then I think pricing remains relatively stable. It will get a little bit more competitive if we see a different commodity price if it's lower. But I think where we are now, that it stays relatively stable.

And your next question comes from the line of Arun Jayaram with JPMorgan.

I was wondering if we could start with the CapEx. You mentioned how you're reducing CapEx by around 15% to less than $500 million. I was wondering if you could maybe unpack the year-over-year decline, what that kind of represents, maybe a little bit of a mix between drilling and completions and perhaps how much of the CapEx is going to be earmarked for the Emerald direct drive of kind of horsepower.

Yes. So I can give you a little bit of color on that. So of our total CapEx projection or CapEx guidance, about 40% of it is going to drilling, about 45% of it going to Completion Services, a little over 10% is going to Drilling Products. And the rest is sort of corporate and other on a percentage basis. And in completions, of that 45%, gross dollars, about $65 million or so is going to new Emerald equipment that will be coming into the fleet over the course of the year.

That's super helpful. Andy, for you. I wondered if you could maybe elaborate on this trend you're seeing with continuous pumping. I think in one of your previous slides I've seen that you've talked about how simul-frac now is representing about 30% frac activity today. Where are we in terms of continuous pumping? And is it advantageous for operators such as Patterson to pursue continuous pumping? Just obviously, I assume you're getting paid for the extra horsepower on site.

Yes. Continuous pumping is interesting in that there are certain advantages for the E&P to -- if they don't have to stop, you're basically pulling production forward. So there's a value to the E&P to do that. And the E&P has to work through those economics to decide what that value is. Because on average, if we're pumping 22 hours per day across all of our fleet, and you want to take that number from 22 to 24, we may have to deploy in terms of capital another 20% to 30% of capital on location with more frac pumps, more high-pressure iron, more valves to be able to have a system out there that can achieve that.

And so the E&Ps -- and we charge for all that equipment when it goes on location. So the E&Ps have to do their own earnings math to decide, is that worth the extra equipment that's on location to be able to accomplish that? Is that value of bringing production forward on that particular pad or multiple pads really worth that effort? So what we see today is we see a number of E&Ps that are trialing it to see how it works, to see what the costs are going to be. And we're working with a number of our customers to reduce those costs so we don't maybe have to put so much equipment on it on there.

So it's all evolving at the same time. But at the end of the day, it's going to be up to the E&P to decide, does it make economic sense for them. Technically we can do it. Technically we know how to do it. We are working to continue to reduce the cost to do it. But it's the E&P's economic decision at the end of the day.

Andy, you said it's 20% to 30% more horsepower at the well site to do that.

I would say 20% to 30% more capital in general because you've got pump equipment. You've got maybe redundancy on a number of things. You've got more piping, more valves out there. Because if you're going to pump for multiple days straight, you still need to be able to access pumps to maintain them. So you have to have more pumps than you're using so that you can swap pumps in and out of the lines while you're circulating without stopping the circulation. So you're going to have more equipment on location so you can manage all that.

Okay. And if I could just sneak in one more. Andy, I believe you were anticipating running around 2 million-horsepower plus or minus in 1Q or currently. What is your average fleet size in terms of horsepower today?

There's no average fleet side. I mean, I can tell you, every fleet that we have deployed is a different size. Is it in the Midland Basin? Is it in the Delaware Basin? Is it a simul-frac in the Delaware Basin? Is it pumping in the Haynesville? And so everyone is different. Everyone has become very bespoke to whatever operation the operator is trying to accomplish.

As I mentioned earlier, just even a simul-frac job, we might have a simul-frac job today that's got another 20% of horsepower versus a trimul-frac lats year because they want to do it at higher rates and higher pressures because they're seeing increases in production. It even changes from pad to pad. It may be a high amount of horsepower on one pad. And for the same customer, moves and it shrinks for the next pad. So it's constantly changing.

And your next question comes from the line of Atidrip Modak with Goldman Sachs.

Andy, I was wondering if you could give us color on the private versus public customer conversations as we think about your exposure in the U.S.

Yes. So we work for some of the biggest publics and we also work for some of the biggest privates in the U.S. And I would say that the large privates think of things long term just like the large public think of things long term. They take a multiyear view to everything and that's how they view it. We do some work for some of the small private equity-backed profits but that's a very small percentage of what we do. We're heavily weighted to the largest E&Ps in the U.S., whether they're both public or private.

Got it. And the Saudi opportunity, it sounded like it's mostly on the bit size because of in-country value. Is that the right way to think about it? Or are there other strategic opportunities for you down the road?

Saudi for now is focused on drill bits for us. And you're absolutely right. It's the in-country value equation that the country uses. And so if you manufacture in-country, it improves your score. It allows your customers to buy more products from you. If you're manufacturing in-country and exporting out to other countries in the region, that improves your score and allows your customer there to buy more from you. So we think that, that's certainly a benefit for us, and our team has done a great job of getting us to the point where we can manufacture the first one in December. And we'll continue from here.

And your next question comes from the line of Keith Mackey with RBC Capital Markets.

Just wanted to start out on the rig side. Can you just talk through some of the technology offerings on your rigs? How has that changed? And what sort of revenue or just net benefit uplift do you get from the technology in this market? And finally to that, more of your customers are starting to talk about robotics on the rig floor. What's your view there?

So in our Cortex automation is a number of applications that enhance our control systems and automate a number of the functions that a driller might normally do when he's operating the drilling rig and working with his crew. And we've developed a number of these applications over the years, and it's been an interesting evolution because as you start to develop applications, then your customer comes back with what ifs. Well, what if we do this or what if we do that?

And that either improves the existing applications where you tweak them some more, where our data analytics team will look at the data in different ways and decide how to best fine-tune these applications, or the customer works with you to come up with a new application that they see as beneficial and ask for priority on that. And so over the years, we've continued to develop those out. And there's revenue involved. We certainly charge for these. But it also means that we become more important for that customer when we're offering these things.

And we tune these applications to their specific procedures or their workflows or their specifications on how they want to see the drill bit go back to bottom or what kind of weight on bit they want to carry on the drill bit or what kind of differential pressures they want to maintain. And so it just allows us to be closer with the customers on how we run those types of operations.

In terms of robotics, our teams have certainly -- they're looking at it. There are some advantages. There are also some big costs. And we've done a lot of the groundwork to deploy that on either our APEX-XC rig or APEX-XK. And I think over time, we'll do that as well depending on what the customers are requesting.

Got it. And just finally, Q4, we're expecting a lot more seasonality from you and several of your peers. Can you just give us a little bit more color on really why you think that didn't happen and things were a lot more resilient? Is there some element of the E&Ps just not being able to slow down given where current activity levels are? Or are there pricing incentives given to keep fleets going? Just what is your sense of really why activity was so resilient in Q4?

I think for us, it was a combination of two main things. It was our customer base. As I've mentioned before, we work for some of the largest customers in the U.S. And those customers have stayed even more resilient than we've thought and just kind of kept working through the quarter maybe more than they normally would. And then the other piece is for some of those customers that may have slowed down, our teams have done a real good job placing that equipment in other places to be able to do that.

Certainly wasn't pricing concessions but really more working with the customers. But again, I think it goes back to our customer base and the ability of our teams to know all the customers so that when we do have to move something around, then we can do that efficiently.

And your next question comes from the line of Eddie Kim with Barclays.

Just wanted to dig into the Completion Services guide for the first quarter. You said you expected gross profit of around $95 million, which represents about a 14% sequential decline. At the same time, you said you expected activity to decline only slightly in the first quarter due to winter weather.

So I mean, that would seem to imply a not insignificant pricing decline from fourth quarter, first quarter. Is that a fair assessment? And should we expect that to be sort of a headwind for you as your fleets move on to this lower pricing level as we move throughout the year?

No, not at all. I wouldn't say this is any significant pricing decline by any means. I think this is all more activity related. You can go back and look at the number of days below freezing in the Permian or the number of days that Pennsylvania had heavy snowfall, and that's where we were held up in activity in the first quarter. So that's just pushing revenue from the first quarter essentially into the second quarter. So that's how that's kind of moving.

In terms of pricing decline, what we've said before even at the last earnings call, we're going to have a slight decline because of various tenders that have happened in the second half of last year, but that's in the single digits. So any price decline on average is single digits. But certainly, that's not what's driving what you're seeing in the decrease in gross profit. It's more had to do with weather activity and some mix and activity during the quarter.

Got it. Got it. Okay. My follow-up is just you opened up a new manufacturing facility in Saudi. You said you're manufacturing drill bits in the country. Could you sort of talk about the growth ramp-up you expect in Saudi maybe this year and next? And do you think Saudi demand is going to be sufficient to absorb all that capacity coming out of that new facility? Or is there going to be opportunity to sell drill bits into other countries in that region in a couple of years?

Yes. Of course, we follow the rig count, the announcements on increasing rig counts in Saudi because that's what drives our drill bit business. They've had a big slowdown over the last 1.5 years in both onshore and jack-up drilling rigs over in Saudi, and we're seeing the calls to put the onshore drilling rigs back to work. And so you've had a number of drilling contractors that operate in Saudi that have made those announcements, and that will start to drive an increase in drill bit demand.

We do expect the customer over there to consume some of their existing drill bits that they might have in a warehouse. But as they go through that, then they'll be calling for new drill bits. And we'll have some manufacturing capacity over there to be able to meet that need. We'll probably still likely ship drill bits from the U.S. at the same time. So it will be a mix of local manufacturing plus drill bits coming into the U.S. until we expand our manufacturing over there.

But real pleased with what the team did given some of the constraints and challenges we had over there to get manufacturing set up. We've been doing remanufacturing in Saudi for years. So it was really a matter of expanding the space, the types of machines that we needed over there and also the skills that we needed over there to be able to go to full manufacturing. But they were able to produce that first drill bit in December.

And we'll take our last question coming from Jeff Bellman with Daniel Energy Partners.

And a bit of a high-level question, and definitely related to some of what you've already addressed, but I wanted to get your take. If I had a thesis that the U.S. industry has gone a long way working through their Tier 1 inventory and activity is going to have to increasingly shift towards, let's say, more complex or Tier 2 resources, how do you view that transition for Patterson? And how does your asset base help operators kind of extend their economic life and expand the resource base if that shift actually has to occur?

Sure. There's a lot of talk about shifting from Tier 1 to Tier 2 and I really think that's operator specific. We work for some E&Ps that tell us they have another decade of Tier 1 that they're still working on. And then we have some E&Ps that say, yes, we're going to start to look at some of the Tier 2 or some of the deeper geological horizons. For us to do that, that means more service intensity, and more intensity means that it's positive for our pricing.

But on the drilling side, it means we may need to continue to add capacity on the size of the rig that we're using. So we'll continue to do that. And on the completion side, it may require more horsepower on location for some of the deeper plays. And so it just increases overall service intensity, which is positive for us.

And that concludes our question-and-answer session. I would like to hand it back to Andy Hendricks for closing remarks.

Thank you. I appreciate everybody dialing in today, and we'll wrap up this call for the Q4 2025. And look forward to talking to you again in April. Thank you.

Thank you, presenters. And this concludes today's conference call. Thank you all for joining. You may now disconnect.

Thank you for standing by. My name is Rebecca, and I will be your conference operator today. At this time, I would like to welcome everyone to the Patterson-UTI Third Quarter 2025 Earnings Conference Call. [Operator Instructions]

I will now turn the call over to Michael Sabella, Vice President of Investor Relations. Please go ahead.

Thank you, Rebecca. Good morning, and welcome to Patterson-UTI's earnings conference call to discuss our third quarter 2025 results. With me today are Andy Hendricks, President and Chief Executive Officer; and Andy Smith, Chief Financial Officer.

As a reminder, statements that are made in this conference call that refer to the company's or management's plans, intentions, targets, beliefs, expectations or predictions for the future are considered forward-looking statements. These forward-looking statements are subject to risks and uncertainties as disclosed in the company's SEC filings, which could cause the company's actual results to differ materially. The company takes no obligation to publicly update or revise any forward-looking statements.

Statements made in this conference call include non-GAAP financial measures. The required reconciliation to GAAP financial measures are included on our website at patenergy.com and in the company's press release issued prior to this conference call.

I will now turn the call over to Andy Hendricks, Patterson-UTI's Chief Executive Officer.

Thank you, Mike, and welcome to our third quarter earnings conference call. The performance of Patterson-UTI has continued to demonstrate resilience this year. And our teams have done a great job executing in a challenging environment and staying focused on optimizing our business in the areas that we can control. We are continuing to see success as we enhance our commercial strategies through additional service and product line integration and performance-based agreements, while at the same time lowering our cost structure, which is helping us to lessen the impact from moderating industry activity this year.

Headlines over the past 6 months have highlighted cautionary signals, including oil supply growth from OPEC+, shifting demand patterns as trade policies evolve and overall global macroeconomic uncertainty. But the U.S. shale picture today is more constructive than many expected just a few months ago.

Oil prices have fallen, but overall, have so far remained more resilient than many predicted, with long-term global demand growth continuing, and anticipated supply additions slower to translate into physical barrels than headlines have suggested.

At Patterson-UTI, while the business environment this year has brought unique challenges, we are adapting with the market, both commercially and structurally, and we continue to generate healthy levels of free cash flow, while still investing to expand our technology edge.

Our efforts and focus today center on driving improvements in our outlook for profitability and cash generation against a steady market backdrop. And each of our businesses are stepping up to this challenge.

In the U.S., oil production does not yet fully reflect the impact of activity reductions over the past 6 months. And we believe current industry activity is already below levels needed to hold U.S. production flat. Any further activity reductions from current levels would likely result in additional pressure on future U.S. output, which could negatively impact global oil supply in 2026.

On the natural gas side, the outlook as we move into 2026 appears to be favorable. Physical demand growth from LNG is now starting to come online, and our customers are beginning to make plans to satisfy the expected multiyear growth in demand, which is likely to require higher drilling and completion activity compared to current levels.

Even as U.S. shale drilling and completions activity has moderated through 2025, our teams have delivered results that are far more resilient relative to prior periods of activity moderation. Our customers are sophisticated, and they are demanding innovative technologies from both our drilling and completions businesses, which is widening the performance delta among service providers. The increasing reliance on differentiated technologies puts Patterson-UTI in a strong position given the high quality of our operations. We expect this relative margin resiliency to continue as customers rely more on high-end service providers.

Operationally, our teams are functioning at a high level in a competitive market. Our drilling team has seen activity stabilize, and our rig count today is slightly above where we were at the end of the third quarter. Our completion activity continues today at a similar level relative to where we exited September, and we expect completion activity will remain steady for most of the quarter, although typical seasonality is likely to impact the segment during the holidays.

As the market steadies, we see opportunities in both our drilling and completions businesses to invest in technologies that are in high demand and short supply, with our expectation that any incremental investments will earn strong returns. As we prepare our 2026 budget, we are working with technology-focused customers on opportunities to deploy new technologies in both drilling and completions, and expanding our competitive edge should widen the advantage we believe we have over much of the industry.

As we approach 2026, while we are not ready to give specific guidance for what we expect next year to look like, we are comfortable saying that we do expect lower capital expenditures compared to 2025. Even on lower CapEx next year, we expect to fully maintain the high demand portion of our fleet as well as invest in new technologies across our businesses, while still generating meaningful free cash flow for our investors. We remain committed to returning at least 50% of our annual free cash flow to shareholders through a combination of dividends and share repurchases.

Moving to capital allocation. We are operating with significant flexibility, with the expectation for continued solid free cash flow and a strong balance sheet, giving us optionality for 2026 and beyond. Our leverage remains low, with net debt to EBITDA of just over 1x. We closed the quarter with $187 million in cash and an undrawn $500 million revolver. And the fourth quarter should deliver our strongest free cash flow quarter of the year, which should strengthen our capital flexibility as we head into 2026. We will continue to deploy capital only towards opportunities we believe will deliver high long-term returns, including the option to further accelerate our share repurchase program.

Our U.S. contract drilling business saw activity stabilize as we exited the third quarter, and we expect this stability to continue through the rest of 2025. Recent revenue per day for drilling rigs remains in the low to mid-30s range. Our directional drilling business is performing exceptionally well, benefiting from strong service quality and new technology deliveries as well as further integrated offerings with both our drilling rigs and our drill bits.

Today, we are focused on driving further improvement beyond relying simply on a recovery in industry activity. We are looking to expand our technology-driven commercial models by growing integration across our products and services and through additional performance-based agreements, as we also work to lower our costs. Our drilling team is delivering strong operational performance for our customers by utilizing our Tier 1 APEX rigs and our suite of proprietary Cortex digital services, including adaptive auto driller and predictive models, which become platforms for future artificial intelligence to enhance the quality of the service we are delivering for all of our customers.

Our customers are seeing the benefits of using a Patterson-UTI rig and our suite of digital solutions and complementary services and products. The digital and technology package remains a key factor to delivering differentiated solutions for our customers, and the investments we have made have helped margins hold above what our drilling business has achieved in previous periods of activity moderation.

Our Completion Services segment demonstrated strong relative performance in Q3, with activity holding steady compared to the second quarter. Our commercial team did an outstanding job managing the frac calendar and aligning us with high-quality customer base, while our operations team executed at an exceptionally high level. Pricing per horsepower hour in our frac business was steady compared to the second quarter, with lower sequential revenue, mostly a function of less sales of low-margin sand and chemical products.

We also started to see benefit of cost reductions in the first half of the year. The completions market remains competitive, but our operational quality is proving to be a major differentiator. We recently set a record for continuous pumping for one of our customers in the Northeast, where we safely pump 348 hours straight on a single fleet. This record highlights the capabilities of our digital performance center in Houston to implement new operating techniques with the support of our local field teams.

Our new proprietary EOS completions platform is advancing our technology edge through 3 primary products: Vertex automation controls, Fleet Stream and IntelliStim. This platform will allow us to further implement artificial intelligence and machine learning into the completions process.

After successful deployment in the third quarter, we continue to deploy our Vertex automation controls across all company fleet, with projection for full deployment by year-end. This will allow us to implement closed-loop automation for all pump types to improve our operating efficiency and asset management, while delivering optimized completion designs for our customers based on real-time surface measurements.

Fleet Stream will provide data visualization and analytics, a platform to acquire and analyze reservoir measurements and streamline data workflows for our customers and provide a new revenue stream for our Completion Services segment.

Finally, in combination we worked on our drilling rigs and through modern machine learning, our IntelliStim reservoir technologies leverage artificial intelligence to provide real-time reservoir insights to better understand rock properties and optimize completion designs to maximize well performance.

We see multiple ways to monetize our digital investments. We are already seeing the investments lower operating and capital costs through higher asset turns. Additionally, on the revenue side, we've already signed 2 customers to commercial deals for 2026, specifically for our EOS platform. And we think there is significant revenue opportunity as well as a path to create closer and more integrated long-term relationships with our customers.

Our Emerald fleet of 100% natural gas-powered equipment remains in high demand, and we continue to strategically invest in new technologies that are driving accretive returns for the business. We've recently taken delivery of our first commercial direct drive pumps, which will allow us to deliver 100% natural gas-powered solutions for our customers with significantly less capital deployed relative to electric frac fleets. The direct drive pumps are scheduled to begin long-term dedicated work in the fourth quarter. We think recent advancements made in high horsepower direct drive natural gas engines have helped make this the most capital and cost-efficient solution for our business.

Our Drilling Products business had another good quarter in North America, where our U.S. revenue per U.S. industry rig set another company record. Since we acquired Ulterra in 2023, we've seen a roughly 40% increase in U.S. revenue per U.S. industry rig, with a more than 10% increase in market share for our drill bit products on Patterson-UTI rigs.

In Canada, we saw a strong recovery in revenue coming out of spring breakup even as total industry activity was slightly below expectations.

International revenue declined, mainly in Saudi Arabia's drilling activity in that country slowed. Outside of Saudi Arabia, revenue was strong internationally, and we expect international revenue to increase in the fourth quarter.

On the margin side, the quarter did see higher-than-normal bit repair expenses in July, which resulted in lower margins for the quarter, although margins recovered towards historical levels later in the quarter.

Our fully integrated PTEN Digital Performance Center located in Houston is the backbone for the entire company. The digital center has been critical as we execute and optimize drilling and completion designs for our customers. The information that we can provide both our team and our customers has improved the efficiency of our operations and brought us closer to our customers as we strive to provide differentiated service.

While U.S. shale activity has moderated this year, we have not stood still. We are focused on finding ways to make our business more competitive, even as industry activity appears likely to remain in a tight range for the foreseeable future. We're using this relative stability to prepare for what we think the industry will look like over the next several years, commit capital to the right areas and execute our own strategy to maximize shareholder value. We will continue to target profitable technology investments that we believe will drive strong cash returns for our shareholders, and we intend to be a leader across all of our business as shale evolves.

I'll now turn it over to Andy Smith, who will review the financial results for the quarter.

Thanks, Andy. Total reported revenue for the quarter was $1.176 billion. We reported a net loss attributable to common shareholders of $36 million or $0.10 per share and an adjusted net loss of $21 million. Adjusted EBITDA for the quarter totaled $219 million.

Other operating expenses for the quarter totaled $23 million, of which $20 million resulted from the accrual of expenses associated with personal injury-related claims for incidents that occurred several years ago, partially offset by a favorable contract dispute resolution. Our weighted average share count was 383 million shares during Q3, and we exited the quarter with 379 million shares outstanding.

During the first 3 quarters of the year, we generated $146 million of adjusted free cash flow. As expected, during the third quarter, we saw working capital benefits, and we expect working capital will be a tailwind again in the fourth quarter.

During the third quarter, we returned $64 million to shareholders, including an $0.08 per share dividend and $34 million for share repurchases. Over the 2 full years since we closed the NexTier merger and Ulterra acquisition through September 30, 2025, we have repurchased 44 million Patterson shares in the open market. We have reduced our share count by 9% since that time. This is in addition to reducing net debt, including leases by nearly $200 million, and paying a dividend that is currently an annualized 5% of our share price.

In our Drilling Services segment, third quarter revenue was $380 million and adjusted gross profit totaled $134 million. In U.S. contract drilling, we totaled 8,737 operating days for an average operating rig count of 95 rigs. Geographically, compared to the second quarter, activity was flat outside the Permian Basin, with Permian activity responsible for the sequential decline in our rig count. For the fourth quarter in Drilling Services, we expect an average rig count to be similar to the third quarter. We expect adjusted gross profit will be down approximately 5% from the third quarter.

Revenue for the third quarter in our Completion Services segment totaled $705 million, with an adjusted gross profit of $111 million. We saw flat activity on a pump hour basis compared to the second quarter, with margins benefiting from improved operating efficiency and some cost reductions that were initiated in the segment during the first half of 2025. We saw improved efficiency as several of our larger fleets that saw gaps in the second quarter had more consistent schedules.

Additionally, our power solutions natural gas fueling business saw an improvement as natural gas demand in the Permian continues to grow as customers look to take advantage of weak regional natural gas prices by using more of the commodity as fuel. Overall, completions revenue was lower on a decline in sales of low-margin sand and chemicals products. For the fourth quarter, we expect completion services adjusted gross profit to be approximately $85 million, with less seasonality compared to the fourth quarter last year.

Third quarter Drilling Products revenue totaled $86 million with an adjusted gross profit of $36 million. Performance was strong in our U.S. and Canadian businesses, while international revenue was impacted by lower activity in Saudi Arabia, which is our largest international market. Margins were affected by higher bid repair expense in July, although they returned closer to historical levels by the end of the quarter.

For the fourth quarter, we expect Drilling Products adjusted gross profit to improve slightly, with relatively steady results in the U.S. and Canada and higher revenue and gross profit internationally. As a reminder, roughly 70% of the revenue in our Drilling Products segment is generated in the U.S., with around 10% in Canada and 20% international.

Other revenue totaled $5 million for the quarter with $2 million in adjusted gross profit. We expect other adjusted gross profit in the fourth quarter to be steady compared to the third quarter. Reported selling, general and administrative expenses in the third quarter were $62 million. For Q4, we expect SG&A expenses will be relatively steady sequentially. On a consolidated basis for the third quarter, depreciation, depletion, amortization and impairment expense totaled $226 million. And for the fourth quarter, we expect it will be approximately $225 million.

During Q3, total CapEx was $144 million, including $47 million in Drilling Services, $81 million in Completion Services, $13 million in Drilling Products, and $3 million in Other and Corporate. For the fourth quarter, we expect total CapEx of approximately $140 million. Our full 2025 CapEx is now expected to be less than $600 million, even before considering the benefit of $33 million in asset sales we have realized through the third quarter. Our updated capital expenditure budget is lower than previously expected.

We closed Q3 with $187 million in cash on hand, and we did not have anything drawn on our $500 million revolving credit facility, and we do not have any senior note maturities until 2028. Through the first 3 quarters of 2025, we have returned $162 million to shareholders through dividends and share repurchases. Free cash flow is likely to remain strong in the fourth quarter, which is expected to be our highest free cash flow quarter of the year. Our Board has approved an $0.08 per share dividend for the fourth quarter of 2025, payable on December 15 to holders of record as of December 1.

I'll now turn it back to Andy Hendricks for closing remarks.

Thanks, Andy. I want to close the call with some comments on our company and the industry. I'm very pleased with our team's execution in the third quarter, where we are outperforming our competitors in many areas of our market. As well, we continue to make the necessary cost reductions to align the company with the projected levels of activity and maximize long-term free cash flow.

This past year has been one of the most unique years since shale emerged as a major source of oil and gas over a decade ago. In many ways, the U.S. shale oil field services industry has outperformed each previous cycle. Our margins are holding up far better than what is typical in periods of activity moderation. Equipment bifurcation and capital availability is leading to disciplined behavior across our industry. And customer consolidation is leading to a more constructive environment at the high end of the oilfield services market relative to the overall market.

Our third quarter results reflected a stabilization of industry activity as we exited the period. And absent normal seasonality in our completions business, we expect activity to remain relatively steady through year-end. We fully recognize and acknowledge that the macro outlook is a driving force and investment decisions. Lower commodity prices have slowed overall activity in the U.S. for the past couple of years. However, our business has remained resilient, and we are focused on investing in technology, maximizing our long-term free cash flow and returning cash to shareholders. And we think our strategy will create the most value for Patterson-UTI shareholders over the long term.

There is much to be proud of with the way our teams are operating. But even as the outlook has stabilized, we are not content to simply wait for a market recovery. We intend to stay focused on our plan to maximize the value of our unique commercial model and technology offerings across drilling and completions. And we see evidence that customers are becoming increasingly receptive to more integration and performance-based pricing, as they too search for ways to improve their own returns. We are just at the beginning of realizing the benefits of that journey for the company.

The goal for our business leaders is clear. We need to improve our position in the markets where we operate. We are confident that our teams are focused and up to the challenge, and we look forward to proving that out over the next year. As we start to prepare for 2026, what we see right now is another year of strong free cash flow. Our balance sheet is in great shape, our liquidity is strong, and we are operating with an extreme degree of capital flexibility.

Our focus on capital allocation should allow us plenty of opportunities to use our free cash flow to maximize the long-term value for our shareholders, including through a potential acceleration of our share repurchase program. We are pleased with the quality of our operations, and we are confident that we can make our business even better.

With that, I'd like to hand the call back to Rebecca, and open up for Q&A.

[Operator Instructions] Your first question comes from the line of Arun Jayaram with JPMorgan.

Andy, I wanted to talk a little bit about completion services. One of the narratives we've heard from your peers is pricing trends continue to moderate even at the higher end of the market yet. You highlighted how your trends on a horsepower basis were relatively flat. I was wondering if you could maybe elaborate on what you think is maybe driving that differential performance there.

Listen, I think our teams are just doing a great job out there and executing in the field, some of the really high-end work that we've done with large simul fracs and trimul fracs. We're burning significant amounts of natural gas. We're delivering that natural gas to location. We're maximizing displacement of diesel in some cases or on full electric jobs or full Emerald jobs, providing significant amounts of natural gas and fuel savings.

And everything that we have to convert natural gas is out and working. And so we don't feel a lot of pressure to reduce pricing from where we're at. Now as you know, the industry discussed, there's been some big tenders over the last few months. Some of those are still in process. But I think, overall, the industry is showing a lot of discipline from where we are right now as well.

Great. Great. And maybe, Andy, you could talk a little bit about your fleet renewal programs as we think about kind of 2026, you highlighted how you expect CapEx to be down at a corporate level. But talk to us about planned investments in Completion Services. It sounds like you're pretty excited about the direct drive pumps in that. So how should we think about fleet replacement for PTEN on a go-forward basis?

Yes, the 100% natural gas direct drive Emerald systems that we've just taken delivery of this quarter and just deploying. We're excited about what we believe is a better use of capital -- better allocation of capital and trying to provide 100% natural gas services out in the field. And so we're excited to have a number of those out working this quarter after shaking that technology down for the last 2 years.

When it comes to 2026, we certainly haven't finalized the budget yet. But what you've seen us do over the last several years is invest at the high end without investing at the low end and just letting the lower end of the equipment just move away from attrition.

We've reduced the overall horsepower we've had over the last few years, from 3.3 million at a peak, down to 2.8 million just by letting that lower-tier equipment go away. And so I think there's a chance we'll make some similar decisions next year. We haven't finalized that yet, but we're not investing at the low end. And I think that helps keep the market tight. And if we see more demand next year for more of 100% natural gas equipment, we'll continue to invest because we're getting good returns on that technology.

Your next question comes from the line of Scott Gruber with Citigroup.

Yes. So power is a hot topic and Patterson has expertise in running microgrids for drilling. So Andy, if we see the data center market pull more megawatts for on-site generation, do you think that opens an opportunity for Patterson to enter the power market within the oil field? How are you viewing that opportunity today?

We have significant technical expertise in power. We have our electrical engineering division that can engineer and manufacture microgrids. On any given day right now, we're producing around 500 megawatts of power across drilling and completions. We operate generators from 1.1 megawatt recips, all the way up to 35-megawatt turbines. And so we have a lot of technical expertise.

But when we look at some of the opportunities as you get into the larger power structures, the AI and data centers are demanding, you're at the 200-megawatt plus. And some, they're up to 1 gigawatt of power. That's not a mobile power solution, that starts to look more like an EPC contract where you've had a lot of big construction going on.

So we're focused on what we can do and where we can bring value. We've discussed with some of our customers, and still do from time to time, to rely power for them in their own operations and production. And if we think that there's a reasonable market there, then we'll provide power for them. But we're very focused on delivering free cash flow. We don't want to spend a lot of capital on things that we don't think are going to bring immediate value for shareholders right now.

So the oilfield production power opportunity for Patterson is still kind of TBD. Is that the right way of saying it?

I would say we have discussions with our customers. These are customers that we're close to. But there's a number of companies that provide PowerForm already and have historically. So it's still a competitive market. If we think we can get a good return doing it, we'll do it.

Okay. And then I wanted to ask a question on the completion side. I know you guys have made some real strides in developing frac optimization software. Can you provide some more color on this, expanding opportunity -- sorry, expanding offering. How many fleets are deploying optimization software today? And is this contributing to the improvement in segment performance despite the micro headwinds?

Yes. So we're excited about what the team has done in terms of digital on the completion side. So they rolled out the EOS platform, and that's an evolving platform that constitutes a large number of products both at the digital center here in Houston, but also in the field. And one of those products is Vertex automation for the frac operations. And so we've already rolled that out in the field and we continue to deploy, and it's going to be on all fleets by the end of this year. And when we say all fleets, our automation can work on our Emerald, electric Emerald, 100% natural gas direct drive. It can work on our Tier 4 dual fuel. So we're not limited as to where we deploy the automation.

And as we've discussed with a lot of you, sometimes we're running blended operations with Tier 4 dual fuel and electric or 100% natural gas direct drive combined. And so our automation controlled software allows us to be able to work across all those platforms and combined situations as well. And we have a number of customers that that's what they want to do. And so we don't have any limitations on the type of equipment we're deploying automation on, and really excited about what that's going to do for us. It's certainly a product we'll be able to charge for.

As I mentioned earlier, there's a number of products coming out of the platform that we believe we can monetize, and this is one of them. It's going to probably provide some improvement to overall reliability of equipment. It's going to help us differentiate on how we deploy fracs in the well, and excited about what we can do with it.

Your next question comes from the line of Saurabh Pant with Bank of America.

Great. Good. Andy, maybe I'll start with a bigger picture question as you talked about macro uncertainty, things seem to have stabilized a little bit where we see where they go from year-end. But as you talk to the customers, Andy, right, be it on the drilling side and the completion side, how does that uncertainty manifest?

I'm just thinking on the drilling side, do they want shorter-term contracts to give them more flexibility on the completion side, maybe this more frequent pricing reopeners as an example, right? How are these discussions going, just given the uncertainty in the environment?

So yes, as we mentioned, activity is stabilized where we're at right now. The rig count for us has come down this year. And -- but the pricing has held up pretty well. There is some pressure. It's a competitive market, but we're still in the low 30s on average. And so if you compare that to what has happened in previous cycles of moderation, we're certainly in a better position today than we have been in the past with an industry. The industry is showing good discipline overall.

In terms of what our customers are saying, our customers are trying to keep their production up. And the wells that we're drilling, while we're becoming more efficient, are also becoming more challenging, both on the drilling side and the production side. We're drilling deeper wells. We're drilling longer laterals. And our customers are dealing in the Permian with wells that have a higher gas ratio.

And so all those things combined to where our customers are trying to keep up the production. And even though we're in a softer commodity environment right now, they're trying to keep their production up for their shareholders. And I think that you're going to see continuing intensity for what we do grow, and we're getting requests to add more technology to be able to meet the needs.

Right, right. No, that makes sense. That makes sense. And I agree, by the way, with your views on the activity levels. They seem like we are right at or below maintenance level, right? So if you want to keep up your production, you're going to keep up your activities. Okay. Makes sense.

And then a quick follow-up, maybe, Andy Smith, for you on the 2026 shareholder returns. I don't know you'll give the framework over time, right? But at this stage, how should we think about share repurchases? It's good to see you spend that up a little bit this quarter versus last quarter, but just maybe refresh us on the framework as we think about 2026.

Yes. I mean, look, it's a little early to be talking about 2026 and what our plans are. We're just on the beginning of our budget cycle. And as we get through that, we'll finalize. And we'll give more color around that going forward. Again, we've kind of given you the backdrop of the market. We're very focused internally, again, on our performance and making sure that we can be as efficient as we can be. And that's really where our focus is today, and we haven't really focused yet on kind of what our buyback program might look like next year.

Your next question comes from the line of Ati Modak with Goldman Sachs.

Andy, you talked about the production impact of the activity changes. But I'm wondering if you see anything in the cycle times or efficiencies across the value chain that could potentially impact the response expectation you laid out?

Well, I think that what we're seeing, where activity is right now, it has the potential to negatively impact U.S. production a little bit. And just voicing that if oil were to stay in the upper 50s for a little while, that probably bring U.S. production down further.

And if you're going to bring U.S. production down further next year, well, the next reaction is, you're going to have a commodity price reaction. And I think there'd be nervousness in the market. So I think it'd be self-adjusting and self-correcting.

So when I think about the long term, I think we're in really good shape from a fundamental standpoint. We may have some changes in commodity prices over the near term, that may affect some activity levels. But over the long term, I think the fundamentals are still good. We're still seeing long-term demand for oil growth over a multiyear period. And the U.S. has to be part of that production as well. It has to be part of that equation.

The discussion for OPEC+ to bring on physical barrels, they haven't really brought as much in terms of physical barrels as has been discussed. And I think that's baked into what we're seeing, too. So I think there's still a balance that we have right now between supply and demand. So -- and we see that with some of the decisions that our customers are making too.

And like I mentioned before, we have customers that are trying to maintain production for their shareholders, but also balance capital spending in a little bit lower commodity environment. But we're staying relatively steady in our activity levels as a result of that. We have customers that are wanting to deploy more technology. They're willing to pay us for it. And to help them with their efficiencies in how they drill wells and how they complete wells in order to maintain their production.

Got it. So for '26, when you are guiding to steady activity levels but also highlighting that gas could drive some, is that -- should we think about that as gas potentially driving upside to that steady expectation? Or is that offsetting some softness in oil?

I think there's upside in gas activity next year. I don't think it's right away in the first quarter. I think that as we see more physical demand from LNG next year, that we've already been doing a lot of frac work in areas like the Haynesville. And there is -- there are wells that have gas behind the valves right now and ready to go. And so I think they're going to address the immediate physical needs in early '26, but eventually, it's going to drive activity later in the year. And I think that's upside for us even if oil is holding steady next year.

Your next question comes from the line of Stephen Gengaro with Stifel.

Two questions from me. Maybe I'll start with -- when we think about sort of RFP season and thinking about what E&Ps may or may not do next year, how are you guys thinking about pricing in the completion market next year? As I'm just sort of thinking about what margins may look like on a year-over-year basis. Any color you can provide around that?

I think that what you'll see is that most of us have already gone through a lot of the tenders that you're having to go through right now. And so what we're saying for projections in the fourth quarter have kind of already locked in some of that pricing. And there could be a little bit of movement in next year. But as I said, everything that we have that converted natural gas today is sold out, and there's still demand for equipment that can burn natural gas because our customers are getting a good fuel savings out of that.

So I don't see pricing as a huge headwind. Are things still competitive? Sure. And if there's any white space in the calendar, which we all know happens from time to time, and we have to fill some dedicated work with some short-term spot work, maybe we take a little bit lower price to do that in the Midland Basin or something like that. But overall, I don't see like a huge headwind on the pricing because I think that the work is relatively steady outside of fourth quarter holiday slowdown.

Great. And the other question just sort of ties into the capital allocation strategy. How do you think about -- you obviously have a view on the market, things seem to be stabilizing. But how do you think about capital returns versus balance sheet strength?

And what sort of signs do you look for to give you confidence in accelerating or continuing to return capital in a market that has kind of disappointed us for 6 or 7 straight quarters?

Yes, Stephen, this is Andy Smith. So as we look at it, again, our -- making sure that we have the equipment in both -- in all 3 of our major lines of business that is top of the market is probably the most important thing that we think about when we're thinking about capital.

And then it really becomes what is the cadence of adding that equipment? What is the cadence of making sure that we're rightsized for the opportunity set that's out there? What are we looking at beyond that in terms of our balance sheet leverage? I don't think that we have any issues right now with leverage, to be honest. I'm very comfortable with where we are. And so that hasn't been as much of a focus, but then we look at the return to shareholders and whether or not we want to over step kind of our 50% commitment to our shareholder base. So that's kind of the order of operations.

We will continue to high-grade our fleet. I mean, look, there are technology changes in all of our businesses over time. They won't be super lumpy, I don't think. They'll be pretty -- I think they'll be sort of pretty consistent over time, but we will continue to make sure that we're providing the best equipment and the best services out there because, again, we've had a lot of questions about pricing on this call, and pricing is going to follow performance. And we started the call today with a point that we're focusing on the things that we can focus on. And really, that's performance. I think we performed well in the field, and we did very well we have this quarter. And we have, for the past several quarters, and I think we will continue to, then pricing won't be quite the issue that it is if we were just thinking about this as a commoditized equipment business.

So I really think that -- we don't have concerns around our balance sheet, if that's part of your question. I'm not concerned with where the leverage is from a capital allocation standpoint. And I think within our free cash flow, we have lots of opportunity to make sure that we're still providing the best services and the best equipment to our customers that we can.

Stephen, I'm just glad that we've committed to give back 50% of our free cash flow to shareholders, and we're on track right now to where it's almost 60% for the year. When we look at these capital allocation decisions, as Andy mentioned, we have opportunities for new technology, and we'll look at each of those on a project-by-project basis. And in some cases, it makes more sense for us to invest in these new technologies in drilling and completions versus buying back the shares. But we're certainly committed to at least 50% to shareholders, and we're running ahead of that right now.

Your next question comes from the line of Derek Podhaizer with Piper Sandler.

Andy, I just wanted to go back to Scott's question. I fully appreciate your views and discipline around power and what you can bring to the table currently. But just maybe -- can we have an EcoCell update? I know typically, that's replacing a diesel generator on the rate with the battery. But just given the outlook for this type of technology, are there potential opportunities outside of oil and gas for EcoCell within your subsidiary of Current Power?

Derek, so I think there could be, and we've had some of those discussions. I think for us, though, the way EcoCell is packaged, it's designed for hazardous environment operations and drilling. It could fit in a production environment. You don't need all those qualifications just to put it next to a data center or an industrial application. We're certainly open and our teams continue to explore those possibilities.

Again, when you get into that space of EPC construction and you're over 200 megawatts and approaching 1 gigawatt of power, you're competing with a lot of different companies out there. And sometimes, when it's an EPC project like that, it's big, the winner is essentially the lowest bidder, and that doesn't necessarily bring value for us. And so we're going to focus on things that we think can produce strong free cash flow.

So it's designed for as well as a variable load because drilling rig surges as you engage the draw works or you engage the pumps in ways that industrial applications don't see. And so we've written custom software to manage that. So it's just a little bit of a different configuration and setup versus what you do for industrial applications.

Got it. That's very helpful. I wanted to ask a question around drilling. So you talked about Permian being a soft spot here, but obviously pockets of strength, specifically in the gas basin. So just thinking about the rig count, it's up a little bit from where you are, you're going to be steady. If you think about the upside to rig count next year, whether that's gas or even the Permian recovering, how should we think about the required OpEx or CapEx invested back into these rigs that have been sidelined?

And just thinking about what that could mean for the future margin expansion once we've rolled through all this contractor and all this pricing and then you're on actually I'm going to reinvest back into these rigs that have been sidelined for quite some time now. Just maybe some updated thoughts how we should think about that with your rig count today.

Yes. We haven't done any of that math recently, but I can tell you, historically, when we reactivated a rig, it's been several million dollars to get a rig reactivated from a capital standpoint. And so we would take that into account any agreement that we're working out. But the other is that as we have some of these discussions with E&Ps for what they're going to need over the next couple of years, they're also wanting more technology on the rig, more capacity on the rig, longer laterals, deeper Haynesville gas, things like that.

And so that's going to drive some larger conversations, but it's also going to drive larger day rates. And so we will look at them on a project by project basis like we always do when we restart a rig. And if we're adding more technology than we normally would or we're doing structural upgrades, then we'll get paid for that at a high return as well.

Your next question comes from the line of Keith MacKey with RBC.

Just wanted to start out first on the drilling services guide for Q4. I talked about a 5% decline in adjusted gross profit, though, on steady activity levels. So can you maybe just give us a little bit more color in terms of the drivers of that 5% decline? Is it more seasonal? Or is there a continued kind of lowering in average pricing on the rigs or something like that?

There's a little bit of decline in the pricing in general. It's relatively steady in terms of activity from where we are today, but we have seen a decline in the overall industry rig count and our rig count since the beginning of the year. So a little bit of a softening in the market that we're dealing with. But my expectation is going forward after Q4 outside of some seasonal things that we have in Q1 to be relatively steady.

Got it. Okay. And Andy, just wanted to follow up on the last question about the rig technology and the incremental capacity that E&Ps are looking for. Can you give us a few examples of the types of things that your customers are asking you for as they look to drill longer wells in various areas across the U.S.?

Yes, we could talk about a few of those points. So first, the easy one is structural. So as we drill deeper wells in the Western Haynesville with the laterals that they're drilling, the casing loads are getting bigger, so the structural capacity is moving up from, say, what we've had over the last decade, which has been a 750,000-pound rig in general for the industry, up to 1 million pounds. And so we're seeing those request for the structural upgrades.

But we have E&Ps that are wanting that as well for the Delaware where we're drilling deeper and longer laterals and they're using more drill pipe and they want to stay efficient, not have to lay down the drill pipe. So they want that structural capacity to be able to rack back more pipe just for those efficiencies in the Delaware. So it's a combination of the 2 and for those different plays, but it's a similar rig style and similar engineering that we have to do for that as well.

The other piece is automation. I'm really excited about what's happening in the areas of automation and what our teams are doing with artificial intelligence. I'll just let everybody know, we had an update with the Board this quarter on all the different artificial intelligence projects that we're doing in the company, and we've let those grow up from our engineering teams and drilling and completion, and excited about the way they're looking at things.

And when we say artificial intelligence, for us, it's not necessarily your traditional large language model that everybody uses on a daily basis. We do a lot with artificial intelligence and machine learning. And we feed data into our systems from our data science teams to allow our models to learn how wells have been drilled so that we can take that forward into the field and deploy those automation and machine learning models onto the equipment, whether it's drilling or completions, and so that the equipment can now function at a higher level with more efficiency, which improves reliability, longevity of the equipment and also brings benefit to the E&Ps as well.

Your next question comes from the line of Jim Rollyson with Raymond James.

Andy, you've been through a lot of cycles and I think you've talked about a little bit on this call, this cycle has definitely been a bit different than typical cycles. And in that, I'm kind of curious, as you think through '26, '27, historically, we come down in a pretty violent manner.

And when U.S. land balances, it kind of comes from both drilling and frac, and you ultimately get pricing leverage again after you've had -- they go in the wrong way for you. And this cycle has kind of played out differently in that pricing has held up better, there's a lot of technology you've kind of discussed. And I'm just curious, as you think through once we hit the bottom and the gas rig count starts to go up and oil rig count eventually starts to recover to replace production, how do you think about how this cycle unfolds?

Because I'm assuming frac probably has better chance of getting pricing sooner just because [indiscernible] but then you've got the technology kind of benefits coming on both sides. So maybe lay out how you -- in your world, how you think this plays out as we get to the other side of this kind of dip.

Thanks, Jim, and thanks for reminding me that I've seen a lot of cycles. I appreciate that this morning.

Yes. This one has been an interesting one where it's really been about 2.5 years of activity coming down across drilling and completions for various commodity reasons. And so we've had to look and say, okay, what's happening next, how do we adjust the company and the structure for where we are, where we think it's going. And we continue to do that. So even though we're saying we think activity is relatively steady from here, we continue to look at the structure of the company and make sure we're rightsized for where we are and where we're going.

With it coming down in the pattern that it has this time, I think there's a chance that the reverse look similar, but there could be a little bit quicker inflection on the gas side. But either way, we see upside from where we are, whether it's continuing to adjust our company for where we are in the market or upside from gas activity later in '26 and '27, we still see upside. So we think we're in a great position. We've got strong balance sheet, lots of flexibility with the cash and continue to deploy technology and get paid for it. And so even though it's -- we're in this -- what do you want to call it, a softening market or moderating market or however you want to describe it over the last period, we're still upbeat about where we are and where the company is in the market.

Got it. That's helpful context. And then maybe lastly, just on the kind of digital suite that you laid out in the completion side that you've already started putting on, and I think you mentioned every fleet will have it by the end of the year.

Maybe some goalposts around what is like the revenue and profit opportunity in that space if you get a high rate of customer adoption? Just when you think about how that maybe offsets the general activity trend that we've seen as we go forward.

Well, I think it's still early days. And on the completion side, we're still signing some contracts to do that and providing those digital services for next year.

On the drilling side, it's millions of dollars a year in revenue that we're generating off the digital. We rolled out our Cortex operating system years ago, and we continue to add applications to that on the drilling side. And now those applications, through our data science team, are incorporating artificial intelligence, will be layered into those as well. And so that's just going to enhance the productivity of those applications.

So I think it's still early days in the technology journey. We've built out the infrastructure. For those of you that have come to see our PTEN Digital Performance Center, you know we've made the investment. We've got the platform. And so now we've got teams that are building on top of that. And we're talking software. This is not heavy capital in terms of an investment, but yet there's revenue upside for us.

Your next question comes from the line of Dan Kutz with Morgan Stanley.

So just wanted to ask on the kind of nameplate Emerald fleet side. I think last quarter, you guys that you had over 225,000 horsepower of capacity. And then you flagged the latest direct drive delivery at the end of this last quarter. Could you just update us on what kind of the Emerald fleet size is at the that latest delivery?

It's around that 250,000 level right now. We've still got some more of those Emerald 100% natural gas that are being delivered this quarter. We're deploying them this quarter and still have some more coming in, but it's still around that level.

In the overall horsepower, which I think is even more interesting. Like I mentioned earlier, we had, had as much as 3.3 million, but we brought that down to 2.8 million. And I think there's others in the market that are doing similar. And that's why I'm constructive on the market for completions and pressure pumping just because I think that overall horsepower continues to come down in the market.

Great. And maybe just to close that out, after everything that has been ordered or you're still waiting for delivery. After all that's delivered maybe by the end of this quarter, what's kind of the capacity of the Emerald fleet at that point?

It will be a little over 250,000, and we'll update you on the next call when we have all those numbers.

Okay. Great. Understood. And then maybe -- you guys have already shared a lot of this, but maybe just to kind of ask directly if you could juxtapose some of the differences between the Emerald electric fleet and the direct drive fleet just on a relative basis, the build costs and maintenance costs, kind of fuel and operating costs, operating efficiencies and maybe a lot of that remains to be seen as you guys deploy the direct drive fleet and actually get the real-time data. But yes, wondering if you could just, at this point, how are you thinking the 2 types of technology would perform and the relative kind of build and maintenance cost between the 2?

Sure. Let me just explain it this way, and I'll give you some high-level round numbers on it. So our Emerald electric is performing really well in the field. We have customers that want to use that. We actually grew the amount of horsepower in our Emerald electric this year because we had customers that wanted to move from standard frac size to simul-frac and trimul-frac with the electric.

When we do that, you also have to increase the power supply at the well site. And so we've gone from, for instance, on one job, a single 35-megawatt turbine up to a 35-megawatt turbine and combine it with some smaller turbines as well to generate enough power to run larger frac spreads than what we would normally do with a 35-megawatt turbine.

The turbines are expensive. 35-megawatt turbine is generally talking about capital costs deployed in the field in the $40 million to $45 million range. And then when we put the smaller turbines out there as well, you're in the $15 million to $20 million range per turbine. So you're talking about a lot of capital costs tied up just on power, and you're also competing in the market for that power with everything that everybody else has talked about and where power is going to go over the next couple of years. So it's not just capital costs, but you're competing for those types of power-generating devices as well.

When we look at the 100% natural gas to drive engines, and these are high horsepower engines, 3,600 horsepower. So it's a new technology that's being deployed versus other technology that may have been deployed in the past couple of years. We're excited about this. This is a great supplier, a well-known manufacturer of the engines and the transmissions and then we spec out the rest of it, including our own control systems on it. And we think that with our control systems on it, we can help manage it.

When you look at the overall capital cost versus an electric with the turbines, I don't have the actual numbers and differentials in front of me, but it's certainly lower. Our teams have done all the work on that. When you look at the OpEx, the OpEx for a natural gas director of engine is going to be higher than in diesel, but the overall OpEx or 100% natural gas direct drive engine, in our projections, is lower than trying to maintain both electric pumps and the turbine generators at the same time.

And so overall, when we look at the amount of capital deployed, you're talking about 25%, maybe 30% reduction in some cases to get the same amount of horsepower at location where you're still burning 100% natural gas. Does that help?

That was very helpful.

Your next question comes from the line of Sean Mitchell with Daniel Energy Partners.

Can you hear me okay?

Yes, Sean.

But keep on hit it on the drilling guide, but I want to turn to the completion got a little bit trying to better understand the typical seasonal slowdown in budget shortfalls and hoping you guys might be able to offer some color on this? At this point, do you have any fleets which have been idled, where you know that fleet will go back to its prior customer in the first half of '26? And maybe any way you can frame the magnitude, that might be helpful.

So we haven't idled any fleet per se. And the way -- the best way I can describe that is quarter-on-quarter, we're still working the same amount of horsepower pumping similar horsepower hours in field, but we've grown some fleets to do more simul-frac and trimul-fracs. So there's been a shuffling of horsepower around to different places.

The fleet count, at the end of the day, is really kind of hard to judge. It's not such a great metric because of the fluctuation in fleet size as we do more simul-frac and trimul-frac. And I think you'll see companies like ourselves where the actual horsepower per fleet grows a bit because we're doing higher intensity fracs. We're doing more volumes on pads, things like that. So -- but we -- to sum it up, we are working the same amount of horsepower, pumping similar horsepower hours quarter-on-quarter. So we didn't really stack any technology.

Yes, Sean, I'll just add to that. When we look out at the fourth quarter and try to predict seasonality, I mean, we're giving a little bit of -- we take an assumption around kind of what we think we'll see in terms of some downtime around the holidays, maybe potentially some downtime around some weather. And sometimes it's better, sometimes it's worse. And so it's -- you just -- as you go through the quarter, you just have to kind of play it as it comes.

Yes. Maybe one more. Just as you talk about a lot of technology, some exciting stuff in the industry today, how much of the improvement initiatives that you're seeing are self-directed versus kind of maybe being requested or suggested by your customers?

I think it's kind of even balanced. We've got customers that request certain things, but we've also got a lot of smart engineers in the company that say, hey, if I deploy machine learning in this way, then we can do this, and it's going to improve our ability to drill a longer lateral or manage how we pump a stage into a well. And so I think it's a mix of both.

Your next question comes from the line of Don Crist with Johnson Rice.

Andy, I wanted to first applaud you for sticking to your guns and which I'll do is a core competency, and not chasing the latest fad as some of your competitors, including very large competitors are doing. But in that vein, I kind of wanted to ask a question about M&A.

We've seen a lot through the E&P side and investors keep on asking all the analysts, is there going to be another wave of M&A on the oilfield service side. And a lot of us don't really see it. But do you see some of your larger competitors that are chasing the power side actually freeing up some of that equipment that could be attractive to you all in the future, to where you could, number one, stick to your core competencies, but go into another kind of M&A transaction that would be accretive in the future, possibly overseas?

Okay. There were several different questions in that one, but let me try to take some of that. So first off, I'll say, we don't have to do any M&A. We're really happy with where the company is today, the cash production profile that we have with the company, the technology deployment that we're doing. So there's nothing that we need to do. We've got great segments that are doing great work and strong competitors in the market today and leading in a lot of areas. So happy with what we have.

In terms of some consolidation, I think that, let's say, on the completion side, there's probably still some room for some smaller companies to get together. And I think that would shore up some of the completions market if that happens over time.

When you look at drilling, it's already a disciplined market. And so not really anything to do there. And so -- we just don't see a lot. And we've looked at a lot of things. We tried to see if there's anything out there similar to Ulterra. We really like the profile of that company, where it's relatively low CapEx compared to our bigger businesses that are heavier in CapEx. And we like what we've done there, and that team is doing a fantastic job. But we're happy with what we have. We don't have to do anything.

Yes. Don, I would just add. As it relates to some of our current competition or industry participants that would be pivoting away from maybe their core businesses, I kind of find that hard to buy today that there would be a wholesale pivot. And so to the extent they would be selling anything out of their sort of fleet, it's probably not going to be at the level of technology that we'd want to participate in or want to buy. So I think probably the likelihood of that is pretty low.

Would that include some international operations? Like I know Bakers sold something to Cactus recently and there may be some other opportunities there. Would something to get a stranglehold on the Middle East be kind of attractive to you all?

Well, I mean I think we'd certainly be interested in looking at it. But I don't put a high likelihood of anything being separated out in terms of our core businesses right now that would come across our [indiscernible] that we probably look at.

At this time, there are no further questions. I will now turn the call back over to Andy Hendricks for closing remarks.

Well, I want to thank everybody who dialed in this morning. It was a really strong third quarter for us. I want to thank all the men and women at Patterson-UTI across all of our segments for everything they're doing and all the great results they had in the third quarter. And just want to say thanks, appreciate it.

Ladies and gentlemen, that concludes today's call. Thank you all for joining. You may now disconnect.