Patterson Uti Energy Inc Q2 FY2025 Earnings Call

Hello, and thank you for being here. My name is Lacy, and I will be your conference operator today. I would like to welcome everyone to the Patterson-UTI Second Quarter 2025 Earnings Conference Call. Thank you. I will now hand the call over to Michael Sabella. You may begin.

Thank you, operator. Good morning, and welcome to Patterson-UTI's earnings conference call to discuss our second quarter 2025 results. Joining me today are Andy Hendricks, President and Chief Executive Officer, and Andy Smith, Chief Financial Officer. Please remember that any statements made during this call regarding the company's or management's plans, intentions, targets, beliefs, expectations, or predictions for the future are forward-looking statements. These statements are subject to risks and uncertainties as outlined in the company's SEC filings, which may result in actual outcomes differing materially. The company has no obligation to publicly update or revise any forward-looking statements. Additionally, statements made during this call may include non-GAAP financial measures. Reconciliations to GAAP financial measures are available on our website, patenergy.com, and in the press release issued before this 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.

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.

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. There are sometimes difficulties 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 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 has 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 long-term value for our shareholders. 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 on 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.

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 further in the year, I think it could stabilize after that as well, which will be encouraging for completions.

I was also curious about the rig count. It seems like stabilization might be possible in the fourth quarter. Is there some gas or oil activity returning if oil remains in the mid-60s? What does the drilling landscape look like that could remain steady in the fourth quarter?

Yes, I'll add a note about today's commodity prices. Looking ahead, we see varying movements in different basins across the U.S. Some areas are experiencing an increase in rigs while others are seeing a decrease, leading to non-concurrent changes in activity. This gives us a situation to navigate. However, there is potential for stability in the fourth quarter, similar to what we experienced last year. We'll need to monitor how things develop, but overall, I'm optimistic about this year's outlook compared to the challenges we faced 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. We are implementing technology across all areas. In Drilling Services, we are consistently launching new technologies, particularly on digital platforms. Our Cortex automation is being enhanced with the development of new applications for drilling rigs every week and month, enabling us to improve our automation capabilities across our drilling rig fleet. This has resulted in an increase in direct revenues from these digital applications. Our digital performance center supports this effort through the REX alert system, which incorporates advanced technology to monitor performance at various organizational levels and for our customers as well. This enhances our overall performance for customers and ensures greater consistency in our drilling operations. On the Completion side, we are actively testing and implementing automated frac capabilities in Appalachia and the Bakken, with plans to expand these capabilities across the U.S. What’s noteworthy is that these automated frac systems are compatible with all our technologies, and we expect to deploy them later this year. We believe this will enhance our competitive edge in the current market while also generating additional revenue opportunities with certain customers who are benefiting from these innovations.

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 tough when you're trying to project and determine what's happening. However, our view for the year is that we expect some decline in the rig count into the mid-90s, but it has the potential to stabilize in the fourth quarter. We observed some stability in the rig count in the fourth quarter last year, so it may unfold similarly for us this year. I believe that's positive for the Completion industry and our activities on that side. This perspective is based on our discussions with customers at current oil prices. Some stability in the fourth quarter wouldn’t be bad at all, and we would certainly welcome that. We'll just have to see how it plays out.

The other question was about the Completion side. You mentioned this briefly, but when we consider the composition of the fleet and the proportion of assets within the industry that are low emission gas-burning, what is the current pricing dynamic between older and newer assets? It seems like newer assets are still affected by market conditions. Are you observing any resilience in this area? How should we approach the pricing dynamics for clean-burning fleets moving forward?

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?

We believe that with the current oil prices, activity levels could be higher. However, due to the fluctuations in the oil markets over the past few months, our customers are seeking stability. If that stability persists, it may create opportunities for growth. Our customers are primarily looking for certainty in oil market conditions, which is a consistent message we hear from them. As we progress through the year, we expect to receive more feedback to determine if oil prices remain stable. Entering the tender season, particularly in the fall, we find ourselves essentially sold out of our top-tier frac equipment. Our Emerald fleets and Tier IV DGBs are fully utilized as we approach this busy period. Although competition will still be present, we currently do not have any available high-quality equipment.

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

I wanted to follow up on your comments, Andy, regarding the Emerald fleets. We understand there are various technologies involved, and you noted that the direct drive recip is becoming more capital efficient compared to some other technologies. Can you provide more details on what you're observing as you expand that technology fleet? How does it measure up in terms of capital efficiency or operational proficiency against some of the more traditional technologies?

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 to provide us with more details on the run rate of investment in Emerald? I know you mentioned you have some additional equipment coming in. Can you share a bit more about what portion of your fleet you think this could or should represent 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 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 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.

We've observed a significant reduction in oil-directed rigs in the U.S., with approximately 45 rigs or around 10% decreasing from the onshore rig count, which I believe contributes to your third-quarter guidance in Drilling Services. However, as others have noted, the guidance for Completion Services in the third quarter has remained stable and surprisingly resilient. Do we expect to see the effects of the decline in the oil rig count in your completion services business in the fourth quarter? Should we consider the expected trend for completion services in the fourth quarter as a typical seasonal decline, along with the additional impact of the reductions in the oil rig count? I'm interested to know if that assumption seems reasonable.

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 as 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?

If we look back at Ulterra's history, which can be challenging since it's been private for quite some time, we notice that they have occasionally gained market share during periods of softer activity. Currently, their customers are focusing on how to enhance efficiency despite efforts to conserve capital, which has led to greater adoption of Ulterra technology. This trend is reflected in our internal metrics; higher technology translates to increased revenue per rig operating in the industry. In the international arena, particularly in the Middle East, our position is steadily improving. We are expanding our remanufacturing center in Saudi Arabia to accommodate full manufacturing, and our drill bits are highly sought after in the region, supported by a strong local team. Additionally, we see potential for growth in offshore areas and North Africa, where our market presence is still limited. Overall, there are ample opportunities for long-term growth beyond the current industry cycles.

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, I'll address that. In all of our businesses, while we have seen some reduction in headcount due to changes in activity, we are also consistently exploring facility consolidations and other ways to reduce costs. Currently, we are in the process of converting our three ERP systems into one. All of these efforts are ongoing and may not be very visible, but they are aimed at improving efficiency and lowering costs. These initiatives will continue as part of our regular operations.

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.

Your 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, we are currently at 2.9 million, as mentioned. About 1.5 years ago, we were at around 3.3 million, then it dropped to 3 million and subsequently to 2.9 million due to a lack of investment in older Tier II equipment. While we still operate some of this equipment, we didn't make new investments, which led to the reduction from an accounting perspective. We continue to add equipment at the higher end, and we will have to observe how that affects our overall capacity, which could decrease as well. The industry is tightening, which could positively impact completions since companies are being cautious with their investments. There isn't a trend towards overinvesting in completions across the industry right now, which is helping to stabilize the sector. All of our Emerald and Tier IV DGB equipment is in operation. As we see some of the horsepower phased out over the next year or two, it should maintain relative balance in the industry. We will still encounter competitive tender processes occasionally, but it will become less challenging as the industry moves closer to balance.

We've received some feedback on this next question, but I want to ask it more directly. Regarding the bundled services and integration, Patterson offers many service lines, and it's clear that increasing our share of the overall drilling and completion process has been a focus for the company. How has the current macroeconomic environment affected this process? Has the market's volatility created opportunities to increase our share and promote more Patterson services to customers, or has it made this process more challenging? I know there has been a notable rise in digital demand within the rig sector. I'm trying to understand how the push for bundled and integrated services has changed with the evolving macro conditions.

Sure. First, I'll begin with the investments we've made in digital technology because it forms the foundation of everything we do, whether in individual operations or the PTEN Advantage package we provide. This investment in digital keeps us competitive in a softening market, which is crucial. It's not solely about the asset or the pricing for the asset, but rather what can be accomplished with the asset. When we incorporate tools like the Cortex automation apps on a drilling rig or the new Vertex automated frac system, we enhance our efficiency, competitiveness, and asset management from a cost perspective. The digital aspect remains essential in driving our competitiveness. This also benefits the PTEN Advantage package. Although the softening market makes it challenging to demonstrate growth in our advantage package, it's holding steady and we're still engaging in discussions with customers in this area. I remain optimistic about this despite the current market softness and the uncertainties we've faced in recent months. If commodity prices stabilize as we approach the end of the year, it will give our customers more confidence to undertake new projects, which bodes well for us too. Thank you, 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.