Operator
The required reconciliation to gap 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 recovery in U.S. onshore activity gained momentum during the third quarter, with activity levels increasing significantly compared to earlier in the year. Against this backdrop, our businesses performed very well, supported by strong field-level execution and investments in technology and premium assets that continue to improve pricing and further strengthen the quality of our customer portfolio. At the same time, we generated strong free cash flow and maintained our solid balance sheet. Looking ahead, we believe Patterson UTI is well-positioned to benefit as the cycle continues to improve. Customer demand for advanced technology is strengthening, while constrained access to capital is limiting the ability or even the willingness of some of our competitors to invest. These dynamics are creating attractive opportunities across our core businesses. We will continue to pursue those opportunities with discipline, deploying capital only where we see compelling returns, and the potential to deepen long-term customer relationships. Our capital allocation priorities remain clear. Target investments that improve our long-term return on capital and our free cash flow per share. Preserve the strength and flexibility of our balance sheet, and return capital to shareholders through dividends and share repurchases, and if appropriate, reduce the macro outlook for U.S. onshore drilling and completions has improved dramatically. Overall, we see a healthy outlook into 2027 across our core oil field services and products markets, particularly for premium equipment and technologies that improve efficiency, reliability, and overall well economics. Today, the increase in U.S. onshore drilling activity has been led by private EMPs, which is typical in the early stages of a recovery. As we approach 2027, however, our conversations with larger public operators are gaining momentum. These customers are increasingly focused on premium technology, including advanced digital, automation, and AI capabilities across our drilling rigs and frack fleets. Larger rigged structures designed for longer laterals and deeper wells, and equipment capable of using natural gas as a fuel. This is the market scenario we anticipated when we increased our CapEx budget earlier this year. Importantly, the performance gap between the industry's highest quality assets and the older, less efficient equipment continues to widen. As activity improves, we expect customers to increasingly prioritize technologies that lower total well costs, enhance operational performance, and reduce fuel costs by using more natural gas. We believe this trend creates an increasingly favorable backdrop for Patterson UTI. For the fourth quarter, we expect industry activity to remain relatively steady compared with third quarter levels. As we move into 2027, as customer budgets reset and considering contracts we already have in place, we anticipate another step up in demand, with 2027 Ford oil prices meaningfully higher than what our customers used to budget for 2026. We expect oil-directed activity to strengthen further into 2027. Based on the demand signals we see today, we believe public operators are likely to account for a significant share of the next round of rig additions. On the natural gas side, the commodity backdrop has been more fluid, although activity across our businesses has remained stable. Our position in the Northeast continues to be steady, consistent with the historical characteristics of that market. In the Haynesville, our activity has also remained stable despite greater volatility in the broader basin. While the overall trajectory of natural gas-directed activity remains less certain, customer demand is shifting toward the same advanced technologies we are seeing to gain traction in the oil basins. As a result, we believe our activity is likely to increase, even if aggregate demand across the natural gas basins remains relatively unchanged. Over the long term, we continue to expect activity in natural gas patients to increase as global natural gas demand continues to grow. Turning to drilling services, activity strengthened during the quarter, and pricing continued to improve. Average rates have increased from the low $30,000 per day range earlier this year to the mid $30,000 per day range, with leading-edge day rates well above the average. Demand has been particularly strong for rigs emerging from our upgrade program, with structurally enhanced rig securing day rates several thousand dollars above our company average. Importantly, demand for these upgraded rigs is highest among larger public and private operators. Several customers have indicated that they expect these rigs to remain integral to their drilling programs for multiple years, reinforcing our confidence in the durability of the opportunity. By quarter end, our rig count was up 16 rigs, or 18%, from the April trough. Since activity bottom, reactivation costs have averaged approximately $1 million per rig, excluding any incremental upgrades required to meet customer specifications. We have a limited number of low-cost reactivations remaining before seeing a material increase in our incremental capital and upgrade costs, at which point additional reactivations would require significantly higher pricing to meet our return threshold. Beyond these limited remaining reactivations, we currently expect growth to come primarily from higher pricing, stronger contract terms, and longer durations, and a greater focus on strategic customer programs, rather than just further rig additions. Based on current demand, we could reach that level of U.S. activity in early 2027. Internationally, we are seeing a growing pipeline of opportunities for our drilling rigs. The opportunities in Argentina are tangible and could develop in the near term. Given the attractive contract terms, we may choose to deploy a portion of our remaining Tier 1 rig fleet into that market. For Venezuela, we have sold rigs and components for 10 AC electric high-spec rigs from the U.S., as well as multiple other rigs from our operations in Colombia. These rigs are actually of higher capacity than was originally used to drill the horizontal wells in the country when I lived there. We may also supply additional equipment to Venezuela. According to completion services, third quarter results improve sequentially, driven by a mid-single-digit increase in pricing from the second quarter. Our completions team continues to work with many of the industry's leading operators who appreciate the value that we bring to their operations, Reflecting the quality of our assets, the value of our digital investments, and our commitment to delivering what we believe is the market's premier completion services offering. Results improved despite elevated non-productive time across several fleets as portions of the completion supply chain tightened late in the quarter. In South Texas, industry-wide sand constraints during much of September resulted in substantial downtime for several fleets, While trucking availability in the Permian periodically limited sand deliveries to location. We believe both issues were temporary, and our operations have returned to full efficiency thus far in the fourth quarter. Looking ahead, the medium-term supply and demand outlook for the completions market is becoming increasingly constructive. The U.S. shale industry has added more than 50 drilling rigs since activity trough this past spring, and current completion activity does not yet reflect the incremental demand those additions are expected to generate. At the same time, higher diesel prices are materially increasing the operating costs of legacy diesel-powered equipment, which we estimate still represents around 20 percent of the U.S. completion industry horsepower in operation today. These diesel-powered assets were only marginally competitive before the recent increase in diesel prices, and even with the improved completion pricing for some equipment, are increasingly uneconomic to maintain. In short, we expect completion demand to move higher over the next several quarters, as available industry horsepower likely declines through the accelerating retirement of older diesel assets. The replacement requirements are further challenged by extended equipment lead times. In our view, the direct drive systems represent the best new technology available, but lead times now exceed one year because these systems are produced on manufacturing lines that also support behind-the-meter power equipment for burning 100% natural gas. These dynamics create an attractive outlook for equipment capable of operating on natural gas. By year-end, nearly 90% of our active horsepower will be powered, at least in part, by natural gas. As we expect the quality of our fleets to improve further in 2027, as natural gas-powered horsepower becomes a constraint on the industry's ability to meet completion demand, we believe we are well-positioned to benefit from the changing competitive landscape. While this backdrop could present attractive investment opportunities that expand our position in the completions business over the next several years, our near-term focus remains on restoring segment returns to acceptable levels before committing capital to address the emerging undersupply. From the past several years through this spring, pricing in our completions business declined by approximately 30%. We have since recovered roughly one-third of that decline, But pricing must move higher before we reconsider our investment strategy. For 2027, we expect to continue replacing anticipated diesel equipment retirements with new Emerald 100% natural gas-powered direct-drive assets while keeping our overall capacity relatively steady. Drilling products. Third quarter results improved substantially from the second quarter. Revenue increased 21%, while we also saw significant margin expansion. The segment delivered its highest quarterly revenue and adjusted gross profit since we completed the acquisition of Ulterra in 2023. Thank you. Thank you. With third quarter revenue from these offerings increasing more than 40% from the second quarter. Downhole tools now account for around 5% of segment revenue, and we expect revenue from this business to roughly double in 26 compared with 25. We anticipate another year of strong growth in 2027. As we are still in the early stages of penetrating several of the markets where we compete with the potential for significant growth in the years ahead. Geothermal is also growing quickly, using our bits quadrupling from the same quarter last year. We have a strong share of the U.S. geothermal market and expect to see additional momentum into 2027. The market continues to develop in the U.S., and we also expect growth internationally, where we are in the early stages of market penetration. While geothermal represents less than 5% of our revenue this year, growth should considerably outpace the overall business in 2027. Our goal is to be the drill bit supplier of choice in every market we serve, combining differentiated technology and superior products with a focus on bringing new products to market quickly and capitalizing on our strong customer relationships. Our performance in drilling products gives us confidence in our ability to grow the business over time while maintaining strong cash conversion. As we look forward toward 2027, we are encouraged by the outlook for US onshore activity and the opportunities ahead for Patterson UTI. Our customer conversations continue to point to growing demand for equipment and technology that improve efficiency, reliability, and well economics. Importantly, we believe our opportunity extends beyond an increase in overall activity. Customers are placing greater value on the capabilities of their equipment and our investments in premium assets, digital technology, and automation aligned directly with us. We should position us well to improve returns across our Thank you. We will be supported by pricing and contract terms that justify the capital required. We will remain disciplined in evaluating those opportunities, with a focus on long-term returns and free cash flow per share, rather than growth for its own set. We are very pleased with our third quarter performance, including the strong growth in earnings and free cash flow. These results reflect the progress we are making as market conditions improve and as our investments in technology and premium equipment contribute to the business. With continuing momentum across our operations and a disciplined approach to capital spending, we expect free cash flow to improve meaningfully in 2027. That cash generation should provide flexibility to pursue attractive strategic investments, return capital to shareholders, and potentially reduce debt, while preserving the strength of our balance sheet. 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 $1,342,000,000, a 9% increase compared to the second quarter. We reported net income attributable to common shareholders of $28,000,000, or $0.07 per share. Net income included $18,000,000 of pre-tax other operating income, primarily reflecting a $22,000,000 gain on the sale of rigs and components for rigs to be used in Venezuela. Adjusted EBITDA for the quarter totaled $264 million, which is adjusted for the one-time gain on the sale of the rigs and components. Our weighted average share count was 381 million shares during Q3, and we exited the quarter with 379 million shares outstanding. As expected, working capital trends improved during the third quarter. Even as we fund CapEx projects that During the third quarter, we returned $62 million to shareholders through the repurchase of 2 million shares, as well as a $0.10 per share dividend. In drilling services, third quarter revenue was $417 million, with adjusted gross profit of $149 million. In U.S. contract drilling, we recorded 9,249 operating days and averaged 101 operating rigs during the quarter. Higher adjusted gross margin compared to the second quarter was driven by a 9% improvement in the average rig count as well as higher revenue per day. Directional drilling also improved meaningfully on a sequential basis with higher revenue and significantly stronger margins. For the fourth quarter, we expect our drilling services rig count to average approximately 104 rigs and exit the quarter above that level. We expect segment-adjusted gross profit of approximately $150 million. We expect to incur reactivation costs during the quarter as we prepare additional rigs for reactivation late in the fourth quarter and in early 2027, and we anticipate additional costs as we wind down our operations in Columbia. In completion services, third-quarter revenue was $808 million, and adjusted gross profit was $133 million. Completion pricing increased by a mid-single-digit percentage sequentially, driving higher revenue and adjusted gross profit. Activity was lower, primarily due to greater-than-expected nonproductive time related to sand availability and trucking constraints. For the fourth quarter, we expect completion services adjusted gross profit of approximately $140 million. We expect higher pricing compared to the third quarter. This outlook incorporates normal seasonal factors, which we expect to be more modest this year, as well as the potential for weather-related delays typical of the fourth quarter. In drilling products, third quarter revenue was $110 million, and adjusted gross profit was $51 million. Results significantly exceeded our expectations, driven by sequential revenue growth across the U.S., Canada, and international markets. Over the past 12 months, markets outside North America accounted for over 20% of drilling products revenue, with the Middle East representing our largest international market. During the ongoing conflict, international revenue continued to grow, although logistics, safety, and personnel challenges increased costs. Even with these cost headwinds, drilling products delivered its highest quarterly revenue and adjusted gross profit since our acquisition of Ulterra in 2023. While we expect the conflict in the Middle East to have an impact on our international business in the near term, strength across the rest of the segment should partially offset the pressures in the Middle East. Additionally, we continue to view the Middle East as a key long-term growth driver of our drilling product segment. For the fourth quarter, we expect drilling products' adjusted gross profit to decline 5 to 10 percent compared to the third quarter, primarily reflecting lower anticipated drilling activity in the Middle East, particularly in Saudi Arabia. Our other revenue was $6 million for the quarter, and adjusted gross profit was $4 million. For the fourth quarter, we expect adjusted gross and other to be steady compared to the third quarter. General and administrative expenses were $70 million in the third quarter. For the fourth quarter, we expect G&A expenses to be approximately $70 million. Depreciation, depletion, amortization, and impairment expense was $222 million in the third quarter, and we expect it to be approximately $220 million in the fourth quarter. During the third quarter, we invested $141 million in capital expenditures. That amount included $55 million in drilling services, $63 million in completion services, $20 million in drilling products, and $3 million in other and corporate. We expect 2026 capital expenditures, net of proceeds from asset sales, to be less than $600 million. We ended the third quarter with $339 million of cash on hand and no borrowings outstanding under our $500 million revolving credit facility. We have no senior note maturities until 2029. Our board has approved a quarterly dividend of $0.10 per share payable December 15th to shareholders of record as of December 1st. I'll now turn it back to Andy Hendricks for closing remarks.
Thank you, Andy. Before we conclude the prepared remarks, I want to leave you with a couple of key points. The conflict in the Middle East appears to have increased the global call on U.S. oil and natural gas production for at least the next several years. As the conflict continues, global oil inventories are drawn down further, extending the time needed to rebuild them to levels most countries consider acceptable. Demand for U.S. LNG is also likely to grow as customers place greater emphasis on security of supply. On Monday, the head of the International Energy Agency said he does not expect energy markets to return to normal in 2027. Oil futures continue to provide attractive hedging opportunities for our customers. Technology demand is rapidly reshaping U.S. drilling and completion, driving demand for upgraded equipment that will further differentiate our business. In drilling, customers need larger rigs, and we believe only a limited number of existing rigs can be economically upgraded to meet next-generation requirements. Growing international demand is also drawing rigs out of the U.S., further tightening supply. In completion, higher diesel prices are increasing the fuel savings customers can achieve with natural gas-powered equipment, driving greater demand for these assets. However, building more of this natural gas-powered equipment requires substantial capital. In general, we believe many completion providers either cannot fund new equipment or need higher pricing and stronger contract terms that improve the overall industry returns. Supply chain constraints will also limit how quickly the industry can respond. Together, these dynamics should create a very strong market for our drilling and completion services business. We will remain focused on technologies that differentiate our company and help deliver better well results for our E&P customers, including digital and artificial intelligence systems, which should result in better returns for our investors. Our approach to capital allocation is straightforward. Invest in opportunities that strengthen long-term free cash flow and create the most value for our shareholders, while maintaining our strong balance sheet. We expect free cash flow to be strong again in the fourth quarter, with meaningful improvement in 2027 and beyond. We continue to evaluate a range of capital allocation opportunities, including high return strategic investments, additional cash returns to shareholders, and debt reduction. I'd like to thank all of our employees for the dedication and look forward to building on the success we have seen this year. We'd now like to open the line for Q&A. I'll hand it back to our host.
Operator
We will now begin the question and answer session. Please limit yourself to one question and one follow-up. If you would like to ask a question, please press star 1 to raise your hand. To withdraw your question, press star 1 again. We ask that you pick up your handset when asking a question to allow for optimum sound quality. If you are muted locally, please remember to unmute your device. Please stand by while we compile the Q&A roster. Your first question is from Scott Gruber with Citi. Your line is now open. Please go ahead.
Yes, good morning, Andy and Andy.
So one of the interesting backdrops here for the domestic land rig mark is just how many rigs are leaving You know, for opportunities in South America and elsewhere. Are you seeing less competition now on incremental tenders as a result? Do you think you'll see share improvement in the U.S. Landry market in 27, given the international opportunities?
You know, I think we're seeing increasing opportunities in both the U.S. and, you know, other markets. And we're seeing, you know, we're going to see competition between these markets. It's really going to boil down to, you know, where can we get the best return for the investment that we have to make to activate the rig or even ship the rig? And so, you know, we're evaluating all these opportunities that are coming across. We're looking at the economics. You know, we continue to upgrade rigs for the U.S. market, but we're upgrading, you know, rigs with the possibility that they could work outside the U.S. market as well if we can get returns that we're happy with.
That's interesting. So you did mention the interest in potentially additional rigs in Argentina. Would that be lease rigs? Would you look to operate rigs in country? What type of scale would you need to do that? And you talked about the competition for contracts. What do you need to see in the U.S. in terms of rate and duration to keep the rigs in the U.S. versus what's on the table in Argentina and elsewhere?
First, I'd say, you know, in the markets outside the U.S., it's ongoing discussions, and we'll keep you posted as those evolve. You know, in the U.S., what we're seeing is pricing move up at leading edge. You know, we started out the year in the low $30,000 range. We're now in the mid $30,000 and moving higher, but we're also seeing the contract terms improve. You know, over the last three years, it hadn't been just a degradation in pricing. It's been a degradation in the contract terms with a shift to risk back to drilling contractors and service providers, but we're slowly moving the risk back to, you know, to the point where it needs to be. All these things continue to evolve, and we're weighing both U.S. and...
Is the duration on the U.S. contracts now, you know, significantly improving? Are you seeing that as well?
It's, you know, it's something that we choose to do or we choose not to do. So, you know, as the rates continue to push higher, we will likely lock in some longer-term contracts. The opportunity that we have today where we see the rig rates still have opportunity to move higher, then we're going to lock in a shorter term until we can get the rates to where we're happy, and then we'll lock in a longer term.
Yeah, Scott, I'll add to that that one of the things affecting that is, you know, So really what the rig, or if it is an upgraded rig, really what that upgrade schedule looks like, and whether or not we've had to put any kind of capital into it or significant capital into it. And to the extent that we have or that we choose to do that, we generally are trying to de-risk that somewhat with the customer. And I'll be honest, that's not a real difficult conversation right now because the customer wants that rig, and that rig is generally one of the most capable in the industry. So, to the extent that we're looking at really good pricing and a longer term, that kind of goes hand in hand with what we're doing in our upgrade program.
Got it. I appreciate all the color. I'll turn it back. Thank you.
Operator
Your next question is from Jim Rolison with Raymond James. Your line is now open. Please go ahead.
Hey, good morning, guys, and thanks for taking the questions. Andy, just kind of circling back to the U.S. rig market, you know, you're 104 rigs average expectation for this quarter. You guys mentioned in the prepared remarks, you know, expectation of that picking up again in one queue and just your conversations with public operators, you know, even going back to what you were mentioning at Barclays, you've got some kind of verbal commitments and things like that. I'd love to understand maybe the order of magnitude of, you know, possible rig ads from the public guys as we look through next year, just given what's happened and kind of where the rig count is today versus where it was, you know, three years ago or so.
Yeah, you know, the pace of increase, you know, was really a significant number of rigs. We went from 88 to 104. You know, our rig count moving higher, not, you know, coming out of, we still see the rig count moving higher. And to publics, we're even increasing rig count for some publics in the fourth quarter and into early next year. And we're even in discussions and signing for rig deployments, you know, towards the middle of next year. So, you know, these are firming up. Some of them are discussions, some of them are signed contracts. But, you know, it's definitely still a draw from EMPs on meeting higher spec.
Yep, understood. And obviously, the crude being north of 80 through next year is probably helpful to those discussions. As a follow-up, just, you know, drilling products had a pretty remarkable quarter. You talked about some of the drivers there. Maybe help us understand how we should think about that growth opportunity, you know, maybe with and without the Middle East normalizing next year, because it certainly was a bigger step than I think anybody was generally expecting. And just kind of love to hear how you guys are thinking internally about growth opportunities.
Yeah, I appreciate the question on drilling products. We don't talk enough about it. They do a fantastic job. They are able to respond quickly to customer demand, so they were able to move quickly here in the U.S. I'll say that we're pushing our capacity on manufacturing here in the U.S. We may have to look at expanding that in some of our other locations, but that's a good problem to have. So the team responded quickly. You know, we're getting some pricing improvement. We're doing very well on market share. And then outside the U.S., you know, there's parts of the Middle East that are doing well. Saudi is, you know, having its own separate challenges right now. Sure, slow down, and then a little bit of land rig decrease right now. But outside of that, how the team is managing that business and what they're doing to continue to grow that business. Take Argentina, for instance, with the plan to increase the rig count in Argentina. I expect we're going to do very well down there as well. And then Venezuela could be a future opportunity for us.
Operator
Appreciate the call. Your next question is from Sarab Pant with Bank of America. Your line is now open. Please go ahead. Hi, good morning, Andy and Andy.
Andy, I think you made a comment in your prepared remarks about having limited number of low-cost rig reactivations, right? If I remember that right, I think that number might be 8 to 10 rigs is what I'm thinking. But correct me if I'm wrong. The question is, do you think those are net adds to the industry, or do you think part of that is because you are upgrading rigs, And there is a lot of demand for those upgraded rigs, so you might be gaining share. And then related to that, if we are adding that many rigs in 2020-2027, how should we think about completions demand coming out of that? Because we know completions lag, and that market is super tight. So just help us think about completions on the back end of that rig demand.
Yeah, thanks. So, yeah, starting with the drilling rigs, some of the upgrades that we're doing are on existing rigs that are operating. But some of these rigs are, we do see the rig count increasing, you know, into next year. And so really pleased with how our teams are progressing, you know, how we're doing managing costs on those upgrades, how things are going with the contract. You know, we're trying to lock in the term, you know, so that we're completely de-risk it that way. But it gives us a lot of future upside as well, having that rig with the higher upgrades. So, with the increasing rig count to the completion story, yeah, the completion demand is going to increase, but it's not clear yet where the supply is going to come from. If you look at how we're managing things, as we've said many times, our pricing went down over the last three years, almost 30%, and we need to get some recovery before it makes sense from a capital investment to actually add capacity, and we don't think we're there yet. We've been ready. That continues into next year. We may get to a point where it makes sense to add in capacity.
Right. No, that's all very encouraging, Andy. Thanks for that color. And then, Andy, maybe this one is for you. I think Andy made the comment that you're running the business for free cash flow per share growth and return, then not growth for growth sake, which is fantastic. But as we think about capital allocation, right, you're prioritizing pricing over just activity growth, but you do have opportunities to deploy capital into these newer technologies kind of strategic opportunities. But if we think about 27 free cash and capital allocation in general, right, how should we think about any preliminary column, maybe on CapEx and any of the other things that we should be mindful of from a capital allocation standpoint?
Yeah, and again, we haven't gone completely through our budget process yet, so I'm not ready to guide to 27 CAPEX, but I will say in general, I don't probably from what we're seeing, you know, this year, you know, again, we talked about and you started your first question with sort of how many rigs do we have left and sort of that easy to put out range. And then beyond that, it becomes, again, a little bit more expensive and pricing really needs to come up. And if you look across, you know, the whole fleet, you know, again, I still think pricing needs to come up kind of for the fleet we have today. So, I don't see us coming in with a capital program that necessarily adds a lot of supply to the industry in any of our core businesses. I do think that as we look at the makeup of our fleet, whether it's in drilling and or completions or incompletions, I do think that we'll continue to high-grade our equipment so that, you know, our equipment will be the best in class and it will be the equipment that we're going to be doing. You know, regardless of the point in the cycle that we're in. And so that's really what our focus is. I don't know that our focus is necessarily going out there and trying to capture a lot of share, but we will continue to try to make sure that we have the best, most capable fleet in the industry in either side of our business.
Yeah, our market, you know, our markets, you know, are in our favor if the industry is short a few rigs and short a few rack.
Right. No, definitely, Andy. Like you said, it's not growth for growth's sake. You're balancing risk. You're balancing return. And if the equation is favorable, you deploy something strategically. But the focus is on free cash flow per share growth, right? And that's the key point, perhaps. Yeah, absolutely. Okay, guys, I'll turn it back. Thank you.
Operator
Your next question is from Alexa Brino with Goldman Sachs. Your line is now open. Please go ahead.
Thanks, team, and good morning. I wanted to ask about the completions market. If completion demand, you know, strengthens again in 27, how do you think about the industry response for new ads, especially just given the capital requirements for high-quality horsepower? Could we see pricing move materially higher before a meaningful supply response, or how do you think about that setup?
Yeah, I'll start and then I'll hand it over to Andy Smith. You know, we, as I've said before, you know, we need to get recovery on our pricing to where, and so, you know, we've been working with our existing customer base. We are adding new equipment in terms of high technology for customers that, you know, that need that to burn natural gas with our Emerald system, but we're also retiring the older tier two at the same time. So our overall capacity is staying level, you know, for the next projected several quarters. You know, unless we get pricing recovery up to the point where, you know, returns cost to capital to add new equipment, it just doesn't make sense. And what we see in the market from some of our competitors, some of the competitors, we either have challenge, you know, justifying a capital spend to grow, and so it really doesn't, you know, show much increase in capacity in the industry over the next year.
I think that frack demand will certainly be higher next year. I don't think there's a lot of capacity out there. I think our industry has had a long history of sort of helping, you know, finance our customers' growth plans using our balance sheets and not getting appropriate returns for it. And until our returns return to where they need to be, I don't think we intend to invest to grow the overall industry fleet.
Okay, that's very helpful. And then maybe just a follow-up on the drilling side. As you talk about some of these high-spec rigs, can you just help us understand a little bit more of what that day rate could look like, and then particularly around contract duration? Is that moving longer at all, or how are customer conversations evolving there?
Sure. We have a large number of what we call our Apex XK rigs that we're upgrading to million-pound load capacity for the deeper wells, longer laterals, Running some slightly heavier casing strings in the deeper wells and just the amount of drill pipe that we have to rack back. So those upgrades are happening right now. But we also have a rig design that we call the XC Plus that we're going all the way to 1.3 million pounds for the deepest wells in the Haynesville. And in the EMPs that are looking at those projects, we're getting extremely Significant upgrade, not just on structure, but on fluid capacities, on torque capacities, a number of things. And so, for instance, we've recently signed a three-year contract to deliver one of those rigs next year with day rates. So that's really the truth.
That's very helpful. We'll turn it over. Thank you. Thank you.
Operator
Your next question is from Derek Podheiser with Piper Sandler. Your line is now open. Please go ahead. Hi there, Derek. Your line is now open. You can go ahead with your question when you're ready.
Sorry, can you hear me? I was on mute. Can you hear me?
All right. Sorry about that. Sorry about that. Just jumping between too many calls. I wanted to go back to Saurabh's line of questioning around just the capacity in your supply. Just thinking about as you move above the 104 rig count level at the end of this year, adding rigs into next year, obviously a big theme for the industry, how many rigs actually could get added back with a little less friction. Is it 110 rigs, 115 rigs, 120 rigs? When does it start to get a little bit more significant from a capital standpoint to really invest in these rigs? Just trying to gauge how the industry could respond if there's a rig count Paul here.
Well, look, I think Surab's, economically, beyond that, it gets much more expensive. And again, I don't have perfect information around what our competition necessarily has, but if I listen to their public comments, I don't feel like there's a lot of excess capacity out there either. So I think, you know, again, pricing is going to need to improve for a significant amount of rigs to come back into the market if that's what the market is really requiring. You know, we'll have to wait and see where we go. But, you know, I would say that from our end, we probably have, again, about 8 to 10 rigs that are, you know, kind of given where we see pricing today that are economic to put back out.
And then on completions, just given some of the efficiencies issues that you guys saw as far as the South Texas sand and some of the trucking and the permit, I'm just curious, just the overall confidence level of the completions industry to bounce back if we do see this demand spike that we're expecting just given the rigs that have been added and the expected rigs added for next year. I mean, we've heard some of your peers talk about these rebuilding costs into the system. So I'd just love to hear your thoughts around any sort of issues around efficiencies into next year if we do get a demand spike in completions.
Yeah, it was a real interesting situation in the third quarter in completions where they were on track for a significant beat versus what we had. And it wasn't long after we had our big analyst dinner, and we all saw each other, and it wasn't just us, but it ended up holding up us and even others as well, with white space in the calendar that we didn't expect. The team did a great job of recovering where they could. Some of the customers actually paid us some standby on some of that, which is a big shift in the market compared to previous years. And so we came in close, but like I said, you know, they were on track for trucking. We are today. We seem to have enough drive.
Okay, great. Appreciate the comments, guys. I'll take it back.
Operator
Your next question is from Steven Gengaro with Stifle. Your line is now open. Please go ahead.
Thank you, and good morning, everybody.
I think two for me, the first is kind of a high-level question. When we think about a lot of your competitors and they're investing a lot of money into new areas, what advantage do you think that gives you in the business? And maybe on top of that, are there areas that are tangential to what you're doing, kind of like Altera, that you've integrated very well, that you would look at as additional business opportunities?
Yeah, I would say that, look, if you think about the capital that's kind of being diverted away from completions into other areas, and I think that's where, you know, if you go back into the history of going back 10, 15 years ago, we're not as significant as they are today. I mean, today you've got our digital offerings, you've got our equipment, you've got our safety programs, you've got, you know, even the cost to ensure this stuff has gone up, so the cost to get into this business is not what it was. I mean, this is a tough business to operate in, and so as you take one of those easy things to solve for being capital and divert it somewhere else, it just makes, you know, those of us that are in the business and have established track records all that much more competitive. So, you know, look, I think it's great. I think, you know, anything that, you know, kind of It takes, you know, my competition's capital and puts it elsewhere is great for us. So from that standpoint, I think it's a positive. And I'm sorry, your second question was around Altera. What was, could you remind me one of them?
Just are there, similar to Altera, without naming specific companies, obviously, are there specific product lines related to drilling or completions that would be kind of top of your list of potential targets?
I think, look, we with Ulterra, if there are those businesses out there, we would certainly be interested in them. Certainly anything in the downhole tools sort of arena. Again, we've got to be selective because those things aren't a dime a dozen. You've got to get out there and kind of do the work and find them. So I wouldn't say that there's a bunch of them running around, but we'll certainly kind of continue to effort that.
Yes, David, this kind of leads into a use of cash discussion. And, you know, with the projections that you guys can do towards year end and even into next year, we're going to be, you know, we'll be sitting on a significant higher amount of cash than we probably ever have historically in the company. It gives us a lot of strategic opportunities, and we've been open that we need to look for.
Thank you. And just one quick one. You may have mentioned this, and I might have missed it. The balance between frack fleets and drilling rigs, I mean, obviously, frack kind of led the way early. Are we at a balance point now, like where the number of rigs out in the market and the number of frack fleets are pretty much working efficiently together, where there's not a shortage of one versus the other? Obviously, you're not building or depleting ducts effectively.
I would say we were at a balance a couple months ago. We're getting phone calls. Hey, I need something. What can you do to help me? I mean, you can certainly see.
Great. I appreciate all the details.
Operator
Your next question is from Eddie Kim with Barclays. Your line is now open. Please go ahead.
Hi, good morning. So you mentioned completions pricing has declined about 30% over the prior three years, and that we've since recovered about a third of that decline. As pricing momentum improves, what level of recovery do you expect we could be at this point next year? Could we recover maybe two-thirds of that decline or maybe even more? And what level of pricing recovery would be required for you to actually consider expanding your position in the Yeah,
I think we have the opportunity to recover all of our pricing in the next year at some point and potentially even more. You know, we'll just have to see how the supply-demand equation really kind of carries out because, you know, if you look at the market now versus even three years ago, you have a little more consolidation in the market, but then you also have some companies that are diverting their capital to do other things. And so there's really, you know, there's a list of companies that are willing to put capital into this completion. And so that's, you know, that's a good setup for a company like ours to generate good return on capital, you know, when we make these types of investments. But, you know, in terms of what we can get in terms of recovery, I think we can get all of our recovery and possibly more.
Yeah, I would also just add to that that, look, as you talk about growing the industry capacity, I mean, you have to, if we're going to put capital into that and think about growing the overall industry capacity, you have to think about it in terms of more than a one-year opportunity, right? So you have to have some visibility or, you know, potentially even, you know, a different contract structure with some of your customers. So, I would say that, you know, until we recover that pricing, I think talk of growing the overall industry capacity is a little bit premature.
Understood. Understood. And then just in your drilling products business, you mentioned that the expected kind of sequential decline here in the fourth quarter is due in part to lower drilling activity in Saudi Arabia. One of your peers recently who had some of their land rigs in Saudi suspended, they suggested that part of the reason for that is because of insufficient frack capacity in the Jafora unconventional basin there. So first, is that what you're hearing as well as to the reason for the drilling-related slowdown? And secondly, I mean, does that present an opportunity for you to perhaps send a few fleets over to Saudi Arabia?
I don't think it's, you know, our place is waiting in that, and I think there are sufficient companies over there to do fracking.
Understood. That makes perfect sense. Thanks for the color. I'll turn it back.
Operator
Your next question is from Josh Silverstein with UBS. Your line is now open. Please go ahead.
Good morning, guys. I'm just curious how you're thinking about your contract duration. Given the tightness in the markets out there right now, are you trying to put more on longer-term duration, maybe not getting peak pricing, or do you want to keep seeing price go higher before you lock in some of that longer-term contract duration? Thanks.
There's kind of a mix to that answer. So, for instance, you know, I mentioned earlier that we've signed a three-year contract for a very large upgrade, and so, you know, we're de-risking the cost of those. We'll look at those types of scenarios, but there's some scenarios.
I don't have anything to add. We've talked a lot about where pricing needs to go, and until it gets there, depending upon which asset particularly we're talking about, was too long of a – if it's a brand new – if it's a new asset coming out of the yard that we've put a lot of money into.
Gotcha. Maybe along the same lines, we tend to think of the public E&Ps and large-scale privates as more of that duration in terms of what they want with contracts and privates, a little bit more short-term in nature. Just given how tight things are, are you seeing the smaller private guys willing to go and lock equipment up a bit longer? It feels like if crude oil prices or gas prices come off, they're more likely to go and drop. But have things changed just because of how tight the markets have been?
I will qualify. The small privates that we might work for are typically privates that have multi-year programs.
Operator
Thanks, guys. Your next question is from Dan Cutts with Morgan Stanley. Your line is now open. Please go ahead.
Hey, thanks. Good morning. Maybe just go back to, I think it was Eddie's question, but brought in and out to the whole Middle East. Any appetite or any conversations or considerations of sending actual assets over there, either in the drilling or completion services sides of the business? Obviously, you have the Turnwell, JB, and close relationship with AdDoc. They're ramping their unconventional plans and activity there. But, yeah, just any appetite or any conversations to send equipment outside of the drill bits business for Middle East unconventional plays. Thanks.
Break it down because it really depends on the country and the market.
That makes sense. And then, so, I guess there's been a lot of talk about some of the logistics bottlenecks that were headwinds in the third quarter on the completion side of the business. But I guess to come at that question from a different angle, it sounds like a lot of the bottlenecks are markets where Patterson has content, like prop and logistics, like natural gas logistics, and powers, obviously, in very high demand in the oil field and in other markets. But I just wanted to kind of check broadly on any trends you're seeing, pricing, demand, anything to flag on the ancillary completion services.
Really good point, because when we do completion work for most...
Got it. It's all really helpful. Thanks a lot. I'll turn it back.
Operator
Your next question is from Keith Mackey with RBC Capital Markets. Your line is now open. Please go ahead.
Maybe if we could just stick with the frack pricing discussion. Just curious, how much of the pricing increases you've seen to date are like-for-like type equipment pricing based on supply-demand tightness versus how much of the pricing improvement has been driven by upgrading to increased natural gas substitution? And how much of that gas substitution are you able to work into your pricing strategy overall to make sure you get improving returns on your overall asset base?
Morning, Keith. Let me back into that question a little bit. So we increase the amount of Emerald 100% natural gas pumps that we have in the field, pricing increase, because we get to charge more for that. And we can use more, what we said was mid-single-digit price increases.
Okay, great. Thank you. The rest of my questions have been answered, so I'll leave it there. Thanks a lot.
Operator
Your next question is from Aaron Jayaram with J.P. Morgan. Your line is now open. Please go ahead.
Yeah, good morning, and thanks for taking my question. Good morning, Arun. Andy, one of the E&Ps yesterday had an interesting comment on what they're doing in completions. Expand Energy, as you know, Andy, largest U.S. natural gas player, mentioned as a result of higher diesel costs, they burn around 25 million gallons a year, that they're switching to kind of natural gas burning equipment or going to try. I think they're running like five or six fleets, they mentioned. I was wondering if you could talk a little bit about, are you seeing that same trend across the industry, and is that maybe supporting some of the differentiated pricing gains that you've been able to deliver just given your high mix of natural gas burning equipment?
I mean, the differential between being able to burn natural gas and diesel is probably at an all-time high. It's tens and tens of millions of dollars per fleet per year, so if you have the ability to get natural gas equipment, which is pretty sold out across the industry right now, but if you have the ability to get that and you have the availability of gas, you would absolutely – I can't speak specifically to what expanded – Yeah, I was just trying to get your take, but I guess the – Yeah, generally, anyone in the industry would be doing that right now.
Yeah, but that could create the backdrop where if a customer, you know, XYZ customer wanted a fleet that they could bid up, and that's how you can manifest pricing gains in a faster, in a clip, yeah. That was kind of what I was trying to get more color on.
Yeah, and we, you know, we continue to bring in, you know, the Emerald 100% natural gas direct drive pump systems, you know, in good numbers every quarter, and we have slots with the manufacturer all the way through next year. And it's, again, it's not that we're, you know, we're not increasing overall capacity of frack supply for what we offer in the market, because we're retiring at the older tier two diesel stuff. But we do get a higher rate for when we put those on location because we blend those in and increase the amount of natural.
Right. And just my follow-up, if we take out, you know, some of the noise in late in the quarter and 3Q, your results in North America are definitely trending better than a lot of your completion peers. Andy, I was wondering if you could highlight what do you think is driving that call differential pricing commentary and whatnot. We have a couple of theories, but I wanted to get your views on what's maybe driving it, because a lot of your peers are not citing the strength and completions that you are.
Yeah, it's great execution and great, you know, the digital infrastructure that we've put in place, and that's what's keeping us highly competitive out there. As I mentioned earlier, if it had mine in South Texas.
Got it. And then, Andy, to what extent have you been able to high-grade the quality of your customer base? I know all customers are important, but obviously you want to be aligned with ENPs that have sufficient scale So you can get the most, you know, drilling and DNC efficiencies from that and give you more utilization on your horsepower.
That's helpful. I'll turn it back.
Operator
There are no further questions at this time. I will now turn the call back to Andy Hendricks for closing remarks.
Today, about the third quarter, it's one of the best quarters. I want to congratulate our teams across all of our segments at Patterson UTI Energy for a great quarter. Thanks a lot.
Operator
This concludes today's call. Thank you so much for attending. You may now disconnect.
