Hello, and thank you for standing by. My name is Lacy, and I will be your conference operator today. At this time, I would like to welcome everyone to the Patterson-UTI Second Quarter 2025 Earnings Conference Call. [Operator Instructions] Thank you. I would now like to turn the call over to Michael Sabella. You may begin. Michael

Thank you, operator. Good morning, and welcome to Patterson-UTI's earnings conference call to discuss our second 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 results -- 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, 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 second quarter saw several macro events take place that raised the volatility in the oil markets. At the start of the quarter, there were fears that evolving trade policies could start to negatively impact global oil demand. While at the same time, OPEC+ was signaling to the market that it would be raising oil production and looking to retake market share. Elevated geopolitical risk emerged later in the quarter, which resulted in a wide range of oil prices between the mid-$50s and the mid-$70s per barrel that made it very difficult for our customers to forecast and make decisions. As we start the third quarter, the macro for oil remains unsettled. In a typical market, today's oil prices in the mid-$60 per barrel range would support higher drilling and completion activity than we are currently seeing. But customers have remained cautious as they look to better understand these macro events. Through all the noise in the markets over the past quarter, the fact that oil prices have stabilized in the mid-$60 per barrel range is encouraging. With regards to U.S. oil production, we believe that until oil-directed activity recovers, we will likely see a larger negative impact on U.S. oil production than we have seen so far, which is encouraging for a long-term outlook relative to current activity. On the natural gas side, we are starting to see early indications from customers that additional activity will start to be added as LNG facilities come online and begin to call for more U.S. natural gas. While natural gas prices have at times this year supported higher levels of activity, the demand for new LNG facilities was further out and customers were hesitant to add additional natural gas volumes to the market while takeaway was still being built. We believe we are now approaching that physical call for higher U.S. LNG volumes, and we expect we will see incremental demand for more drilling and completions activity in natural gas basins as we enter 2026. As the market finds its footing, we expect that we will have opportunities to create value for our shareholders with our differentiated and leading-edge commercial strategy. Our operational footprint, growing technology portfolio and financial position should allow us to improve our position across our core markets. Volatility will create opportunities for companies like Patterson-UTI, and we are prepared to take advantage of these opportunities by prioritizing capital allocation decisions that create long-term value for PTEN shareholders. From a capital equipment perspective, we are operating high-quality fleets of drilling rigs and completions equipment. But it is the investments we have been making to support that equipment that create our long-term competitive edge. We are growing our digital portfolio, and it allows customers to take our top quality assets and layer in automation and machine learning to deliver a more efficient and cost-effective solution. Our PTEN Digital Performance Center, which just opened this spring, is an integrated digital platform that our customers are using to help optimize their entire drilling and completion process, and the benefits of these investments are only just starting to emerge. As the shale market begins to look beyond the current volatility and prepare for the future, we see an oilfield services market that is poised for change. The companies that help drive this change stand to benefit, and we have positioned Patterson-UTI to lead the industry into the next phase of development. It has now been almost 2 years since we closed the merger of Patterson-UTI and NexTier and the acquisition of Ulterra. The operational integrations were completed in 2024, but the ultimate strategic vision for the company went far beyond simply being satisfied with the cost synergies that came from those transactions. We are at the early stages of realizing the benefits of this strategic vision. Over the next several years, we see upside relative to the market as we move further down the path of more integration, automation, closer connectivity between the service provider and the customer and a smarter and savvier shale industry that relies more on data to create value. We have built a company that can deliver value to the customers beyond just the capital equipment, which should allow us to continue to deliver strong free cash flow for our investors. Our strong balance sheet will allow us to be opportunistic as we navigate the market and should help us improve our returns. We closed the quarter with $186 million in cash and an undrawn $500 million revolver, low leverage and an investment-grade credit rating. We are poised to see free cash flow in the second half of the year well beyond what it will take to fund our dividend, and we are exploring ways to best put that cash to work. Our U.S. Contract Drilling business largely tracked industry activity during the quarter, and we continue to see margins hold at levels significantly higher than we have seen in previous periods of moderating activity. Our margins have remained resilient, which we believe shows the technology edge we have built as our customers sees improved efficiency with the Patterson-UTI rig and digital drilling platform. Even as industry activity moderated, we increased revenue from our drilling automation technologies. Customer demand remains strong for our proprietary products that enhance the drilling process, including our Cortex automation platform, which enables our advanced machine learning auto driller application and our REX cloud-based early alert field monitoring system, which we are using these technologies to support a broader customer base as we advance the use of artificial intelligence to improve the efficiency of our drilling operations. Increased acceptance of these technologies is creating a more sustainable customer relationship as we prove out the growing performance advantage of our high-performing rigs compared to other similar capital assets in the market that lack equivalent digital products. Moving on to Completions. Our Completion Services segment saw slightly reduced activity during the quarter, which was largely the function of some customer gaps in the calendar on several of our larger dedicated fleets. We filled most of these gaps with spot work for new customers, which helped to offset some of the changes in customer activity. Our Emerald fleet of 100% natural gas-powered equipment has grown to more than 225,000 horsepower. Our Emerald fleets and our Tier IV dual fuel fleets remain fully utilized. Our Completions business achieved a key technology milestone on our automated hydraulic fracturing, which we call Vertex. There is growing acceptance for automated frac pump controls, and we are already working in the Bakken and in Appalachia and are on track to complete fleet-wide deployment of this technology by the end of 2025. Through Vertex, we see the potential for our equipment to get to rate faster and run at the optimal rate for each pump, which should reduce costs, lower our maintenance capital and also improve the overall use of natural gas as a fuel. Our PTEN Digital Performance Center is the backbone for the entire company as we make significant strides to uniquely help our customers better their plans, execute and optimize drilling and completions designs based on real-time information. Our Drilling Products segment had another very strong quarter with sequentially higher adjusted gross profit. The U.S. market saw revenue improve compared to the prior quarter even as the industry activity declined, delivering another quarter of record U.S. revenue per U.S. industry rig. The business made big strides as it grows its presence across the U.S. International revenue was steady, although we did see higher revenue in several key markets, including the Middle East. The Canadian market, which represents just under 10% of segment revenue, had a great quarter despite the impact of normal seasonal spring breakup. One of our latest technology advancements, our Maverick drill bit continues to have significant traction in the market as we have had success in our Drilling Products business through constant innovation and through downhole tool technology. For Patterson-UTI, our businesses have come together to create what we believe is one of the most formidable companies in our industry. Our foundation remains our top quality, capital equipment and our breadth of offerings at the well site. But the long-term strategic vision has been to build a company with an unmatched operational digital edge and the investments we have made are only just starting to bear fruit. It has been a multiyear journey for our company to execute the vision that we set out for at the time of the merger, and we believe the commercialization of these initiatives is perfectly timed as our customer base becomes larger and more sophisticated. We expect this should lead to continued strong free cash flow and better returns profile for our investors. 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 $1.219 billion. We reported a net loss attributable to common shareholders of $49 million or $0.13 per share, which included a $28 million impairment related to our drilling operations in Colombia. Adjusted EBITDA for the quarter totaled $231 million. Our weighted average share count was 385 million shares during Q2, and we exited the quarter with 385 million shares outstanding. During the first half of the year, we generated $70 million of adjusted free cash flow. We saw a working capital headwind of roughly $119 million through the end of the second quarter, which is typical of our business in the first half. We expect working capital will be a tailwind in the second half of the year. During the second quarter, we returned $46 million to shareholders, including an $0.08 per share dividend and $16 million for share repurchases. Since we closed the NexTier merger and Ulterra acquisition through June 30, 2025, we have repurchased more than 37 million PTEN shares in the open market, which exceeds the shares we issued for the Ulterra acquisition. Including the impact of dilution, we have reduced our share count by 8% 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, first quarter revenue was $404 million and adjusted gross profit totaled $149 million. In U.S. Contract Drilling, we totaled 9,465 operating days for an average operating rig count of 104 rigs with our sequential change in activity roughly in line with the industry trend. On June 30, we had term contracts for drilling rigs in the U.S., providing for approximately $312 million of future day rate drilling revenue. Based on contracts currently in place, we expect an average of 48 rigs operating under term contracts during the third quarter of 2025 and an average of 27 rigs operating under term contracts over the 4 quarters ending June 30, 2026. For the third quarter, in Drilling Services, we expect an average rig count in the mid-90s. We expect adjusted gross profit of approximately $130 million. Revenue for the second quarter in our Completion Services segment totaled $719 million with an adjusted gross profit of $100 million. We saw calendar gaps on multiple long-term dedicated fleets during the quarter, although we filled most of those gaps on spot pads for new customers. We also saw higher revenue from several of our key customers and saw improvements in natural gas basins relative to the first quarter. For the third quarter, we expect Completion Services adjusted gross profit to be relatively steady sequentially. Second quarter Drilling Products revenue totaled $88 million with an adjusted gross profit of $39 million. Drilling Products revenue improved in the U.S. even as industry activity moderated, and we also made gains in several of our key international markets, including the Middle East. Our Canadian business saw typical seasonality from spring breakup, although sequential results were much better than the industry activity as we made gains in several key markets in the country. For the third quarter, we expect Drilling Products adjusted gross profit to improve slightly sequentially, with our results in the U.S. seeing some impact from the lower rig count. Our expected activity in Canada should benefit as that region comes out of normal spring breakup, while international revenue is expected to improve slightly. Other revenue totaled $8 million for the quarter with $2 million in adjusted gross profit. We expect other adjusted gross profit in the third quarter to be steady compared to the second quarter. Reported selling, general and administrative expenses in the second quarter were $64 million. For Q3, we expect SG&A expenses will decline slightly sequentially. On a consolidated basis for the second quarter, total depreciation, depletion, amortization and impairment expense totaled $262 million, which included the previously mentioned $28 million impairment related to our Colombian drilling business. For the third quarter, we expect total depreciation, depletion, amortization and impairment expense of approximately $230 million. During Q2, total CapEx was $144 million, including $55 million in Drilling Services, $69 million in Completion Services, $15 million in Drilling Products and $5 million in other and corporate. With regards to our capital budget for the remainder of the year, we expect capital expenditures net of proceeds from the sale of assets of less than $600 million in 2025. We are reducing our full year 2025 maintenance capital expenditures given slightly lower activity. However, we are still seeing strong demand for new technology in both our Drilling and Completions businesses related to digital and automation services and for advancements in technology to more cost effectively drill and complete longer laterals at higher temperatures and pressures. These investments should improve our competitiveness over the next several years, and we expect these investments to earn a strong long- term return on capital. We believe that our level of integration will uniquely position us to capitalize on these investments. As we approach our 2026 capital budget process, we have significant flexibility within our future capital spend, and we'll reassess market dynamics later this year. We closed Q2 with $186 million in cash on hand. We do not have any senior note maturities until 2028, and we do not have anything drawn on our $500 million revolving credit facility. Through the first half of 2025, we have already returned almost $100 million to shareholders through dividends and share repurchases. Free cash flow is likely to accelerate in the second half as working capital needs decrease. We expect free cash flow in the second half should significantly exceed our dividend, and we are continuing to explore the best use of cash to create the most long-term value for our shareholders. Our Board has approved an $0.08 per share dividend for the third quarter of 2025, payable on September 15 to holders of record as of September 2. I'll now turn it back over to Andy Hendricks for closing remarks.

Thanks, Andy. Our second quarter results reflected a moderation in activity across our core markets, and we are pleased with the way our business has responded to the changing macro. They are sometimes difficulty in delivering on the high expectations that we set across the entire company for our teams, but we're fully confident in our team's ability to rise to the challenge. Operationally, we are seeing more opportunities to use our technology and unique operating footprint to enhance efficiency for our customers and deliver free cash flow to our investors. The volatility in the market will create long-term opportunities for the top-tier service providers like Patterson-UTI and the investments we have made over the past several years into our PTEN Digital Performance Center, combined with our top quality capital equipment will differentiate us relative to our peers. As the market settles and macro uncertainties subside, our suite of digital and automation products have positioned our company as a long-term leader. We are excited about the company we have built and believe we are just beginning to see the strategy play out. From a financial perspective, our balance sheet remains solid. We closed the quarter with a substantial cash balance and see the opportunity for significant free cash flow in the back half of the year. This is allowing us to reinvest in multiple leading-edge technologies that will extend our operational edge and create value for our shareholders long term. And finally, on the macro, current oil production has yet to see the impact of the latest round of activity moderation. While customers remain cautious, we also do not believe the current level of activity can be sustained without a larger negative impact to production volumes than we've seen so far. This gives us some encouragement on our long-term outlook relative to what we are seeing today. On the natural gas side, we believe global LNG markets are nearing a higher call on U.S. natural gas physical volumes, and we believe customers are already starting to make plans and partner with service companies that can most effectively help them satisfy that call. Patterson-UTI has made investments over the past couple of years to prepare the business for what we saw as the next phase in shale development, where more digital services and automation will be used to drive further efficiency. We believe we are just at the beginning stage of realizing the benefit of those investments. We remain excited about the future of our industry and our company. With that, I'd like to turn it over to Lacy to open the calls for Q&A.

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

I want to start on the Completion side. The flat 3Q outlook is definitely solid in light of the macro here. What's your early look into 4Q telling you? Halliburton suggested a pretty steep year-end decline. You guys sound pretty booked up at least for 3Q. But how does that look for 4Q? Are you thinking it could be a pretty steep year-end decline or with weaker activity in 2Q, 3Q for the industry is kind of a more normal seasonal pattern in 4Q, the more likely result?

Yes. First off, when it comes to Completion activity, I want to congratulate the team on what they were able to do in the second quarter. As we had said earlier in the quarter that we were going to have some white space in the calendar towards the end, and they did a great job filling that. And then also on what they're doing in the third quarter and really just keeping the calendar full. And so we're going to be relatively steady in the third quarter. And so that bodes well for us for the year. I think it's too early to call what the fourth quarter looks like. But I would say based on some of the things that we're hearing from the customers for some of the long-term plans and even as we discuss LNG physical volume takeaways in '26, I think there could be moderation in Q4, but I'm not sure yet it's a steep decline for us. So I think it's a little early to call Q4. We do think it softens a little bit, but we're not sure to what degree yet in terms of completions. And because we operate a large fleet of drilling rigs, we have some visibility on the overall market. And I think that really kind of plays a key in how we look at things. And while our rig count is going to come down in the mid-90s in the third quarter, looking out farther in the year, I think it could stabilize after that as well, which will be encouraging for completions.

Got it. And that -- I was going to ask about the rig count, too. So stabilization, it sounds like it's possible into 4Q. Is that some gas activity coming back or some oil activity coming back if oil stays here in the mid-60s? Kind of what's the complexion of the drilling work that could hold steady in 4Q?

Yes. And I'll caveat everything on today's commodity prices as well. But when we look at what we've got going forward, there's different movement in different basins across the U.S. So you've got some rigs going up in some basins, some rigs going down in some basins. So we've got movement to deal with that aren't concurrent in the same basin. And so that's what we've got to work with. But it does have the potential to be steady in the fourth quarter, and it was steady in the fourth quarter last year as well. So we -- again, we'll have to see how that plays out. But I would say, overall, I'm encouraged for what we see for this year versus what we were trying to deal with back in May.

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

Just wanted to follow up on Scott's question about third quarter specifically with the completion activity. You've obviously talked about steady here, which has a bit of converse from some of your peers. Maybe just if you could unpack that a little for us, Andy, the different puts and takes. Is that a gas versus oil comment? Is it spot versus dedicated? Just maybe a little bit more on the third quarter outlook for completions.

For us right now, it's just kind of steady in the basins. We'll have a little bit of movement between some fleets moving to different places. But overall, just kind of steady. No real commentary on one basin for another on completions right now. We're working for some really solid customers, both in gas basins and oil basins. We're applying a lot of digital technology. The new Emerald fleets are out there burning 100% natural gas and we've grown that this year. And so we're in a good position there from a technology standpoint, and I think that's keeping us busy.

Got it. That's helpful. Maybe on a lot of digital commentary and technology commentary in the release, which was great to see. You talked about being strategic with your cash balance and how you can deliver long-term returns for your shareholder. Maybe can you talk to us about what we could potentially see with how you scale that, whether it's technology, bolt-on tuck-ins, you could bring these types of assets on to the Patterson platform and scale. Maybe just give us an idea of what you're thinking about growing your technology in digital and potentially some M&A related to that.

Yes. And it's technology across the board. In Drilling Services, we continue to roll out new technologies, especially on the digital platforms. When we talk about Cortex automation, there's -- the teams are writing more applications every week, every month to work on the drilling rigs, and we continue to expand our ability to be able to run those automation applications on the drilling rig fleet. And so we've seen the revenues -- direct revenues from those digital applications continue to move up. And all that gets supported by our digital performance center here where our REX alert system has advanced technology to be able to flag performance at different levels of the organization and even for our customers who sign in and use it. And so it's really improving our ability to perform for the customers overall and be more consistent on how we drill wells. On the Completion side, we've been testing and now running automated frac capabilities. in Appalachia and the Bakken, and we're going to be expanding that across the U.S. And the interesting thing for us, it's not limited to any one particular technology. We can run automated frac systems on all of our technologies, and we'll have that out and deployed later in the year. And so we anticipate that, that improves our ability to compete in the markets, which we have to be able to do in a market like today, but also layer in some extra revenue at times with some customers as well for the benefits that they're seeing.

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

Andy, you noted increased conversations around gas-directed activity. Can you give us any more color on those conversations and the implied trajectory as we should think about maybe early thoughts into '26, maybe both on oil and gas then?

Yes. So the gas discussions have been interesting because I think this year, there was a lot of talk early in the year that there'd be some uptick in gas towards the end of the year. And we've seen some small increases in gas activity this year, and it's been material for us. But we're expecting more gas activity next year just based on the discussions that we're having. Now when you look at the overall physical LNG volume demands that we're going to see in 2026, '27, '28, some of that's initially going to come from wells that are already behind pipe, behind the valves, ready to go. But we have customers as well that want to increase their activity, and they're talking to us about drilling rigs. They're talking to us about completion equipment. They're talking to us about technologies and upgrades and additions and both digital equipment as well to be able to handle this. So we're in those discussions for 2026. And so I think we're going to see some further increase in the activity in '26. The oil markets right now at today's oil prices are just kind of holding steady for us towards the end of the year. But I think that it will be gas that shows some uptick next year, and then we'll see what the oil markets do in terms of the price or if our oil-producing customers get more confident around where oil prices are today and the stability in that oil price. So we'll have to see how that plays out later this year and early next year.

And then on the private exposure, can you give us any color there, thoughts around what you're seeing? Because you're hearing, obviously, on the gas side, maybe frac engagements and rig engagements are probably stronger there, but private oil also matters a lot to you. So thoughts there on the private side?

Sure. We don't necessarily work for some of the smaller privates that are private equity backed that are really focusing on cash flow or proving out some acreage for a flip. We tend to work for the larger companies and especially in oil privates, and that's been relatively steady for us. And so really pleased with what we do for those companies, the level of technology that they operate, the efficiencies they get. One very large private that we work for actually drills wells for large public operators as well because they're that efficient. And so that keeps us steady and pleased with our position in that part of the market. But again, you may hear different stories from what private equity-backed E&Ps are going to do, but that's a small exposure for us.

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

So I know it's probably early, Andy, and I was curious if you could kind of give me your thoughts. When you gave some guidance on the rig count for the third quarter, it seems like gas activity should start to get a little bit better, maybe late this year, early next year. Can you talk about where you think the rig count or maybe at least activity for you sort of bottoms on the drilling side?

I'm really hesitant to call a bottom. It's always a little bit tough when you're trying to project out and determine what's happening. But our view for the year is that we're going to see some -- a little bit of decline in the rig count into the mid-90s, but it has the potential to stabilize in the fourth quarter. And we saw some stability in the rig count in the fourth quarter last year. So it may play out that way for us this year. And I think that's positive for the Completion industry as well and what we do on the Completion side. So I think that's just all based on our belief in discussions with customers at current oil prices. But some stability in the fourth quarter wouldn't be a bad thing at all. And so we would certainly welcome that. So we'll just have to see how it plays out.

And then the other question was on the Completion side. And you touched a little bit about this. But when we think about the makeup of the fleet and the percentage of assets that you and the industry have that are low emission gas burning assets, how is that pricing dynamic right now, sort of old versus new assets? Are the newer assets still getting -- it feels like you're still getting hit with the market. But what are you seeing? Are you seeing resiliency there? And how should we sort of think about the pricing dynamics for the clean burning fleets as we kind of go forward here?

Yes. So let me explain how we see that and how the market is actually reacting to that and why we're investing in what we're investing in. So when you look at our Emerald fleet that burns 100% natural gas, and that's a mixture of electric fleets. We have some turbine direct drive in there, and we have a growing fleet of natural gas recip direct drive in there as well, which we think is going to be more capital efficient over the longer term. And so all of that because it can burn 100% natural gas is in high demand. And all these types of systems by the end of this year, and we'll have the ability to be part of the digital automation that we're implementing on the frac as well, which will improve their operational capabilities. And so all that's still getting premium pricing, and it's not being pulled down by lower-tier services in the sector. And so we still have a fleet of more of the Emerald 100% natural gas that we're going to receive later in the year and be deploying that towards the end of this year and early next year. And it gets a premium price and margin compared to everything else. Now there is some competition in the 100% natural gas area, and we have to compete in that area. But the good news is it's not being pulled down by the competition at the lower frac technologies. And so that's why we still continue to invest and plan to receive more of the Emerald 100% natural gas systems later this year.

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

Andy, maybe I'll ask a big picture question, right? We've asked a lot of questions on activity and pricing. But before that, right, just looking big picture, spot oil price, like you said, looks attractive. Activity should have been higher, right, but it tells us that maybe operators are afraid oil prices may go down, right? So in that environment, Andy, look, in a few months, we'll be in the budgeting season, RFP season for 2026, right? So as you talk to customers right now, what are you hearing, Andy? What kind of oil price do you think they're going to plan at? Or do you think we are planning at right now?

Yes. And so we think that at today's oil price activity can be higher than it is. But because of all the fluctuation in the markets, and I'm talking about the oil markets over the last couple of months, our customers are just looking for some stability. And if that stability remains, then I think it puts us in a better position to have some upside. But that's what our customers are really kind of looking for some stability and some certainty in what those oil markets look like. And those -- that's what we're hearing from the customers. So I think that as we move through the year, we're certainly going to get more feedback and more comfort in whether or not oil prices are stable at this level. Now going into, say, the tender season, which a lot of it is on the completion side, which we see every fall, it's interesting that we're going to go into that season right now essentially sold out of our highest quality frac equipment. Our Emerald fleets and our Tier IV DGBs are all working. And so we're going into that tender season with that position. And so I think that it will still be a competitive season, but we are sold out of that level of equipment today.

Right, right. No, that's good color, Andy. And Andy Smith, maybe a couple of quick ones for you. One, Andy, if you can help us on CapEx. How should we think about '26 CapEx? I know maintenance CapEx is coming down this year, right? But maybe give us the big pieces in '25 CapEx budget to help us think about '26. And then a quick one on -- I see the, I think, $8 million and change in other operating income in the Drilling Services results in the second quarter. Can you just tell us what that is?

Yes. So on CapEx for '26, we're not ready to kind of give anything that's a guidance number out there yet. With activity coming down, obviously, you'll see maintenance come down, but we haven't gone through a budgeting cycle, so I don't want to get too far out ahead of that. So I'd prefer to maybe talk about that either at the next call or even in the fourth quarter. On the $8 million, there's a couple of things. One, we had an insurance settlement on some equipment damage from -- to be honest, a couple of years ago. That -- and then we also -- that's where we account for income in some of our JVs goes through that line item as well. So that number will go through -- or that's what goes through that line item within our Drilling Services segment.

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

Just wanted to follow up on your comments, Andy, on the Emerald fleets. We recognize there's some different technologies built into there, and you mentioned the direct drive recip is starting to look more capital efficient relative to some of the other technologies. Can you just give us a little bit more color on what you're seeing with -- as you work -- as you build out that technology fleet? How does it compare in terms of capital efficiency or operational proficiency versus some of the more conventional technologies as well?

Sure. When we started down the path of 100% natural gas several years ago, even as a combined company, we were looking at different technologies, and we've tried different things because we've got customers that benefit from burning 100% natural gas for various reasons. And there are several different technologies that you can use to achieve that. And certainly, electric frac powered by 100% natural gas turbine is an effective way to do that from an operational standpoint, but it's also very expensive. It's very capital heavy. So you've got all the pumps on locations, but then you've got the power systems on location, you got the cable systems and you got switchgear. And when I say switchgear, you can say it quick and it sounds easy, but switchgear on a location with a 35-megawatt turbine can be 1 or 2 18-wheeler trailers of breakers and switch and handling equipment to distribute the power. And so this is all capital intensive when you get into the power system attached to the electric pumps on the trailers. 35-megawatt turbine capital out for that can be in the $40 million range. And with turbine technology and turbine power, you're also coming up against the demand for bigger systems for other industries as well, which everybody is talking about. Now when you move on into turbine direct drive, we run a little bit of that. We'll use that to boost natural gas demand on some of our Tier IV dual fuel and boost that demand for the natural gas and improves the efficiency of how that operates with natural gas. So we'll do some of that. We also intermix some electric with Tier IV dual fuel. So sometimes the electric is not deployed all by itself. But then we've also started moving to the 100% natural gas recip engine. So we've been testing that engine for a couple of years. It's a high-horsepower engine, 3,600 horsepower, which can drive a little bit higher horsepower overall than even some of the Tier IV DGB systems that we run. And so you improve the amount of horsepower on the trailer. You don't have all the electrical handling equipment. You don't have to worry about a $40 million gas turbine on location. And some of our frac fleets on the electric are even growing to the point where we're running 35-megawatt gas turbine at $40 million and then maybe another 6-megawatt gas turbine for another $20 million. And so that's a lot of capital on location. And so when you can package that the way we're doing now on the natural gas recip and it just becomes more capital efficient in deploying high horsepower, 100% natural gas operations. And so we're excited about how that's working. Over the 2-year period, sure, we've broken a few things on the system, but this is a great partner in Caterpillar, who we've been working with now for a couple of years to shake things down and they made some modifications to some transmission pieces and some other things. And so we're really confident in the ability to have a partner that's that big in the industry that has experience running these types of engines and the combination and how they're recommending it all be packaged and the reliability that we can potentially get out of this on top of the capital efficiency for deploying at the well site. And if we can be more capital efficient at deploying at the well site, then we can be more competitive in the market versus, say, the electrical systems. And I think this is where we're moving right now and excited about the potential for this.

Got it. Yes, very helpful. Are you able or ready at this point, I guess, to give us a bit of a -- a bit more color on the run rate of investment in Emerald? I know you mentioned you got some more equipment coming in. Can you just talk a little bit more about how much of your fleet do you think that this could or should make up over the next few years?

Yes. We'll take it on a year-by-year basis, but you can see that it's really been kind of a steady add to the fleet, steady investment over the last couple of years. This year, we added some more electric Emerald as we grew from normal frac to simul-frac and trimul-frac for some of our electric customers. And then we're going to add the -- some more of the natural gas direct drive systems this year. And there's a potential for us to add more next year, but we'll take it on a year-by-year basis and make sure we understand the demand and make sure we can understand we're still getting good returns on this.

Your next question comes from the line of Grant Hynes with JPMorgan.

So on the call, you've talked a lot about sort of the different tech offerings, but maybe I was just interested in hearing some more about sort of the integrated advantage offering where you kind of bring the full suite of services. And just thinking about the potential uptick in gas activity. What customers do you think are most likely to adopt this offering from you guys?

Yes. So in general, over the last year or so since we've rolled this out and been doing this for customers, it's been more of the mid- tier customers who have acreage, who have runway in drilling and completions for wells, but at the same time, maybe they don't have large operational teams, and we can help work with them using our teams, they work in our performance center and our digital platform to pull data together and analyze their historical operations and make some recommendations on future operations to pull all this together. And so when we've done this, it's been very successful on all fronts. And I think we'll see some continued demand at that sector of the market. But I think as we get into '26, there's potential for us to work for some of the bigger customers as well that have some bigger operational teams because definitely in the Permian Basin, the word is getting out with the ones that we're working with that we are making improvements. And I think that there may be some of our bigger customers that might want to try it as well and see how it goes. But it's certainly gaining traction, and it's allowing us to even improve our own operational efficiencies and how we manage things on some of the other jobs as well. And so I'm upbeat about how that's going. In a market like this where it's -- we have softening activity, it doesn't show up as much. But I think over the next few years, you'll see that grow.

That's great. And just a follow-up. I think previously, you'd mentioned potentially 15% or so margin uplift from some of these projects and 20% or so higher revenue content. Do you see that being driven more by, I guess, higher sort of attachment rates of your technology offerings or also a combination of efficiencies just from the fully integrated project?

Yes, there's a couple of keys there. One is the pull-through of all the different segments and subsegments that we have when we go to work for these customers and then also the upside on the efficiency gains and helping them pull production forward.

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

So we've seen quite a few oil-directed rigs come out of the U.S. onshore rig count, about 45 rigs or about 10%, which I think is contributing to your 3Q guidance in Drilling Services. But as others have mentioned, 3Q guide in Completion Services remain steady, was surprisingly resilient. But do we start to see some of that -- the impact of the oil rig count decline show up in your completion services business in the fourth quarter? And so conceptually, should we think about the trajectory of completion services in the fourth quarter as kind of normal or typical seasonal decline? But on top of that, you layer in some of the impact of the oil rig count declines we've seen? Just curious if that is a reasonable assumption to make.

So I think let's start with the discussion on the overall industry rig count. And you've got to recognize that there's still some bifurcation in that rig count. So when you see the rig count decline like it has, and we talk about 40-plus oil rigs coming out of the market, a large number of those rigs that are coming out of the market are really the lower technology rigs and rigs that are working for maybe some of the smaller private equity-backed type private companies that are out there. What you're seeing is our rig count is coming down a bit, but not to the extent necessarily as the overall market. And I think that the overall rig count could even come down further this year, but that doesn't necessarily line up with what we're seeing in the higher spec rig market. And so I think towards the end of the year, you could see some of the smaller private equity-backed companies want to conserve capital and slow down drilling and completion operations. But we don't have much exposure to those companies. We're working for the larger companies that tend to have the longer runways, longer budget cycles and things like that and are running higher technology of both drilling and completions. And so that's why you're seeing us relatively steady in Completions in the third quarter. And I think it's the reason that even though our rig count is going to soften some more in the third quarter, that there's a higher likelihood that it stabilizes in the fourth quarter. Now in terms of completion activity in the fourth quarter, it's certainly early to call. We always see some seasonal decline unless there's a really high spike in a commodity price that were to drive some different behaviors. So I think we will see some seasonal decline. But also looking at some of the customers that we work for, it may be a softening in the market for us. I'm not sure yet it's a steep a decline as we saw in Q4 last year. But again, it's still early to tell. And I'm caveating all this on today's commodity prices.

Got it. That's very helpful. My follow-up is just on capital allocation. You highlighted in prepared remarks that you're focused on putting cash to work. So just based on the conversations around the various opportunities you're having today, would you be more likely at this stage to invest more in kind of bolt-on acquisitions in your core oil and gas services business? Or would you maybe be more inclined to perhaps purchase other nat gas resets or gas turbines for the distributed power market like some of your peers have announced in recent quarters. Just curious around your latest thoughts there?

Yes. So we're holding a good cash position right now. Really pleased with the cash flow of the company this year and what we're projecting for the second half. And we're really evaluating some organic technology growth. And some of it is associated with longer laterals and more efficiencies in the Delaware Basin, some of it associated with natural gas demand, physical demand in '26 and '27 and some of the discussions we're in. So we do get good returns on some of these technology investments that we make, whether it be upgrades on digital automation or structure on a rig or even some more of the Emerald 100% natural gas. And so we're evaluating that. We're also evaluating potential to buy back shares as well. When it comes to acquisition, I'll just say, and we've said this before, really pleased with the Ulterra acquisition. I think this helps change the profile of the company to a higher return basis as Ulterra is essentially a product and manufacturing business, and pleased with that. We tried to acquire that company 7 years ago, and we were successful a couple of years ago. But we think there's opportunities to expand what they do and expand some of the technologies in downhole solutions that they're coming up with not just drill bits, but some of the downhole tools that they're building as well. We may be injecting some more capital and then for growth in the international market. So I think we have a lot of things to choose from, and we're just trying to be careful about how we evaluate. But back to the cash position, really pleased with our cash position and the cash flow that we're looking at for the year.

Your next question comes from the line of Connor Jensen with Raymond James.

Just building off what you said there, Ulterra seemed like a relative bright spot with solid results and guidance for further improvement. Can you just speak to some of the growth drivers there, maybe where it's gaining share internationally and some of the upcoming offshore prospects?

Yes. If you look back at Ulterra's history, which is hard for you all to do because it's been private for so long. But when we can see all the numbers and what they've accomplished as a team, they actually tend to gain a little bit of share sometimes in these activity softenings. And so what we're seeing in the market today is their customers getting focused on what can we do to improve even though we're trying to conserve capital, how can we be more efficient. And that's when they start to employ more of Ulterra technology. And so we're seeing that today. And when they -- when it's higher technology, it's higher revenue per bit for rig that's operating in the industry in terms of our internal metrics, and they continue to improve on that. In international markets, in the Middle East, the position continues to improve. In Saudi, we're in the process of expanding our remanufacturing center to do full manufacturing. And our drill bits are certainly popular in the Middle East region, and we've got a great team over there. And we see opportunities still to grow in offshore, North Africa and some other areas where we're just not very big in the market. So we still have upside in other markets, too. So they're in a great position for growth longer term outside of some of the cycles that we're seeing in the industry.

Got it. And then margins have held up pretty well across the whole company given the downturn in activity. Is there anything you're doing on the cost side to adjust to the softer market? Is it just general headcount reductions? Or is there other things you're working on there?

Yes. So I'll address that. In all of our businesses, we're -- while we have seen some direct headcount reduction certainly with activity changes, we're also looking always at facility consolidations and other areas where we can take cost out of the system. We're even currently undergoing an ERP conversion where we're taking 3 that we operate in now and converting to 1. So all of that kind of operates in the background and probably not very visible to you guys, but it's all designed to sort of make us more efficient and take cost out of the system. And so all of those efforts continue and will continue as sort of ordinary course stuff.

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

Andy, I was hoping you could provide a little more color on the moving parts in the Drilling Services guidance. I appreciate the reasons you're no longer reporting U.S. drilling margin per day, but it really seems like guidance embeds a pretty sizable decline in that daily margin.

Doug, some of that is, as we're seeing some movement in different basins in the third quarter, where we've got some rigs that may be coming down in one basin coming up in another basin. If that was all happening simultaneous in the same basin, it would be easier to manage from a cost standpoint, but it creates a little bit more cost challenge as we work through the third quarter and work through some of the movement of what we're seeing. So we've got some oil basins where some rigs may soften a little bit. We may have some natural gas basins where it's coming up a little bit. And so trying to work across those makes it tougher to get some of the cost efficiencies out. And so that's really kind of what's happening in the third quarter.

That makes sense. And then I guess, just how would you characterize pricing for super-spec rigs today?

I'd say right now, pricing is still relatively steady. Leading edge is still around low to mid-30s in general. But the interesting thing is we're seeing higher demand for digital products on top of just the assets. And so yes, I mean, the asset is important, but it's what you can do with that asset and what you can layer on as well and how can you make that asset more efficient. And we're certainly getting more recognition from our customers and our ability to do that.

Your next question comes from the line of Jeff LeBlanc with TPH & Company.

You mentioned that your Emerald and Tier IV equipment is fully utilized, but how should we be thinking about the utilization for the balance of your fleet? And then additionally, how would the market have to evolve for you to consider idling this equipment or pushing it back into the broader fleet?

Well, let's talk about what we're doing in the CapEx budget. We continue to invest in maintenance and maintain all of the equipment with the exception of lower tier Tier II completion. And we have a little bit of Tier II equipment still mixed in with some of the fleets here and there, but we're really not putting any dollars into that. So you'll see Tier II diesel equipment continue to drop out of our fleet, but I think it's not just us. You'll see that continue to drop out of the industry as well because some of the smaller companies that run that in some of the more competitive basins like the Midland Basin probably are more challenged to even generate enough cash flow to maintain that equipment. So I think you'll see a combination for us of adding some horsepower at the higher tier, but also letting horsepower come out at the lower tier. But across the industry, I think you'll see more of the lower-tier horsepower drop out over the next year as well.

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

So maybe just staying on that line of questioning around frac supply, would love to dive in a little bit deeper there. I remember you guys had, at one point, put out, I think, a 400,000 diesel retirement at the end of last year, now you guys are up to 500,000. How do you think about capacity versus the 2.9 million horsepower you're at right now for Patterson going forward? Does roughly the diesel retirements or the diesel assets that you're not investing and maintaining, does that kind of offset any additions to the fleet, any Emerald investments? Like is 2.9 million the right number moving forward? Or how do you think about how that could change over time?

Yes. So yes, we're at 2.9 million now, as you mentioned. If you look at where we were 1.5 years ago, we were at about 3.3 million. We came down to 3 million. We came down to 2.9 million and that's really just by not investing in that older Tier II equipment. We were still running some, but we didn't invest and then eventually brought that number down from an accounting standpoint. As I mentioned, we're still adding at the higher end, and we'll have to wait and see how that balances out, but we could be lowering the overall horsepower as well. But I think the industry is tightening as well. So I think it bodes well longer term for the completions because I think people are being prudent about how they're investing. And we don't see a rush to overinvest in the completions across the industry right now. So I think it is balancing out the sector. As I mentioned earlier, we have all of our Emerald and our Tier IV DGB working right now. And so with some of the horsepower continue to drop out over the next year or 2, I think it keeps the industry relatively in balance. I mean there's -- we're still going to have the competitive tender processes from time to time, but it makes it less challenging when we go through those tender processes when the industry gets closer to balance.

We've gotten a few anecdotes on this next question, but I wanted to just kind of ask it more directly. So on the bundled services and integration, Patterson has a lot of service lines and you've made clear that taking more kind of wallet share, more components of the overall drilling and completion process has been a considered initiative by the company. How has the kind of prevailing macro backdrop made that process? Is it -- has kind of choppiness in the market created opportunities to kind of take more wallet share to push more Patterson services to your customers? Or has it made it more difficult? I know you flagged that digital demand has really been picking up in the rig space. But yes, just trying to think through how kind of pushing the bundled and integrated services has evolved as the macro has evolved.

Sure. So first, I'm going to start with the investments we've made in digital because it's really kind of the backbone of everything we do, whether it's individual operations or even the PTEN Advantage package that we offer. And that investment in digital is keeping us very competitive in a softening market, and that's really important. It's not just about the asset. It's not just about what we charge for the asset, but what you can do with the asset. And when you layer on some of the -- whether it's the Cortex automation apps on a drilling rig or the new Vertex automated frac system, it allows us to be more efficient, more competitive and even manage those assets better from a cost standpoint. And so it's the digital that's really kind of the backbone that's going to help us out and continue to drive our competitiveness. Now that also helps out in the PTEN Advantage package. given the softening market, I would say that it's harder to show growth in those -- in the type of advantage package that we offer, but it's holding relatively steady and still having discussions with customers in that area. So still encouraged by that in a bit of a softening market right now and with the uncertainties we've seen over the last few months. And if the commodity prices stabilize and show stability for our customers as we get closer to the end of the year over the next few months, that allows them to have more confidence to take on some of the projects that they would take on, and that's positive for us as well.

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

Andy, I know there's likely little upside for you to answer this question, but I'll try. As you think about '26, you noted you're sold out of the higher-quality frac assets, yet margins within the broader frac market remain relatively weak. I mean I'm sure your newer stuff is higher margin. But I think it's clear, returns for the industry need to go higher. So I'm curious at what point do you say to your team, hey, guys, let's raise rates and see where the chips fall?

Yes. John, this is Andy Smith. Look, I mean, that's a constant conversation, right? I mean it's not -- that's not something that is -- we don't just decide one day, hey, guys, let's try to push rates. We're always trying to push rates to get the most we can in a competitive market. Now as we invest in additional equipment, and look, I think we're uniquely positioned to be able to invest in technology and equipment that could really lead the industry given the strength of our financial profile, we will kind of be holding our team's feet to the fire on pricing and say we're not while there may be some element of spec to it, we're not doing this entirely on spec.

No. And I'm not trying to do a curveball because like if you step back and think about it, a lot of times you talk -- you hear from folks that it does -- like the spot market, it doesn't really make sense at current returns to reactivate stacked equipment. And if people are true to their words on that, if the industry -- again, not Patterson-UTI, right, let's just say the industry starts to -- were to try to change ways. I mean, I'm assuming you wouldn't want to reactivate a stacked fleet at the current pricing. So I'm just trying to reconcile like at some point, your pricing has to go up. I'm telling you what you know. But just who would take that work if someone tried to then displace you, I guess, is where I'm going.

Well, I think it gets back to bifurcation in the market as well because we're essentially sold out right now, the Emerald 100% nat gas systems and a Tier IV DGB. And there's really not anything that's going to cause me to want to activate a Tier II diesel, even though I might have some on the sideline right now. We haven't been investing in it. It's parked. We'll make some accounting judgments on that later. But we're working everything we've got essentially right now, which is also relatively positive as we get into the tender season, too. And so I think that the industry is relatively tight on the higher-end equipment working for the higher -- the more sophisticated larger E&Ps. And so I think that market is still relatively tight. I mean it's competitive. And yes, the high-spec rig count is coming down a little bit right now, but it's still a relatively tight market in Q3.

This concludes today's question-and-answer session. I would now like to turn the call back over to Andy Hendricks for closing remarks.

Thanks, Lacy. I want to thank everybody who dialed into the call today. I also want to thank the ladies and gentlemen of Patterson- UTI for everything you do every day to help our customers drill and complete wells, and that wraps it up for this quarter. Thank you very much.

This concludes today's conference call. You may disconnect.