Patterson-UTI Energy, Inc.

Hello and thank you for standing by. My name is Lacey 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. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star followed by the number one on your telephone keypad. If you would like to withdraw your question, press star one again. We ask that you limit to one question and one follow-up. Thank you. I would now like to turn the call over to Michael Sabella. You may begin.

Thank you, operator. Good morning. Welcome to Patterson UTI's earnings conference call to discuss our second quarter 2025 results. With me today are Andy Hendrix, President and Chief Executive Officer, and Andy Smith, Chief Financial Officer. As a reminder, statements that are made in this conference call that refer to the company's or management's plans, intentions, targets, beliefs, expectations, or predictions for the future are considered forward-looking statements. These forward-looking statements are subject to risks and uncertainties as disclosed in the company's SEC filings, which could cause the company's actual results to differ materially. The company takes no obligation to publicly update or revise any forward-looking statements. Statements made in this conference call include non-GAAP financial measures. The required reconciliation to GAAP financial measures are included on our website, patenergy.com, and in the company's press release issued prior to this conference call. I will now turn the call over to Andy Hender, 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, OPEX Plus 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 from 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 P10 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 P10 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 helped 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 two years since we closed the merger of Patterson UTI next year and the acquisition of Altera. 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 were 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 US 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 customer sees improved efficiency with a 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 RECS 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 4 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 p10 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 product 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 multi-year 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 court.

Thanks, Andy. Total reported revenue for the quarter was $1,219,000,000. We reported a net loss attributable to common shareholders of $49 million, or 13 cents per share, which included a $28 million impairment related to our drilling operations in Columbia. Adjusted EBITDA for the quarter totaled $231 million. Our weighted average share count was 385 million shares during C2, 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 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 next year merger and Altera acquisition through June 30th, 2025, we have repurchased more than 37 million P10 shares in the open market, which exceeds the shares we issued for the Altera acquisition. Including the impact of dilution, we have reduced our share count by 8% since that time. This is in addition to reducing that 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 trends. On June 30th, we had term contracts for drilling rigs in the U.S., providing for approximately $312 million in 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 four quarters ending June 30th, 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 segments 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 recount. 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 15th, to holders of record as of September 2nd. 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 businesses responded to the changing macro. There 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've made over the past several years into our P10 Digital Performance Center. Combined with our top quality capital equipment will differentiate us relative to our peers. As the market settles and macro uncertainty 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 have remained 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. 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 Lacey to open the calls for Q&A.

At this time, I would like to remind everyone in order to ask a question, press star then the number one on your telephone keypad. Please limit to one question and one follow-up. We will pause for just a moment to compile the Q&A roster. Your first question comes from the line of Scott Gruber with Citigroup. You may go ahead.

Yes, good morning, Andy and Andy. Good morning, Scott. I want to start on the completion side. You know, the flat 3Q outlook is definitely solid in light of the macro here. What's your early look into 4Q telling you? You know, 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?

Yeah, 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 you know, 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, you know, we're going to be relatively steady in the third quarter. And so that bodes well for us, you know, for the year. I think it's too early to call what the fourth quarter looks like, but I would say you know, based on some of the things that we're hearing from the customers, you know, for some of the long-term plans, and even, you know, as we discussed 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, you know, 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 completion. 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 would be encouraging for completion.

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

Yeah, and I'll caveat everything on, you know, 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 US. 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 again, we'll have to see how that plays out. But I would say, you know, 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 Podhyzer with Piper Sandler. You may go ahead.

Hey, good morning. 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 been a converse from some of your peers. Maybe just if you could unpack that a little for us, Andy, the different puts and take. Is that a gas versus oil common? Is it spot versus dedicated? Just maybe a little bit more on the third quarter outlook for completion. Thank you.

You know, 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. You know, the new Emerald fleets are out there burning 100% natural gas, and we've grown that this year. And so, you know, we're in a good position there from a technology standpoint, and I think that's keeping us busy.

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

Yeah. And it's the technology across the board, you know, in drilling services, we continue to roll out new technologies, especially on the digital platforms. You know, 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 uh you know we've seen the revenues direct revenues from those digital applications continue to move up and all that gets supported by our you know digital performance center here where you know our our rex alert system uh has advanced technology to be able to flag you know 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, you know, we've been testing and now running automated frac capabilities in Appalachian 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 the 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 Octedra Modak with Goldman Sachs. You may go ahead.

Hey, good morning, Kim. 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?

Yeah, so the gas discussions, It's 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. 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, 2027, 2028, You know, some of that's initially going to come from wells that are already behind pipe, behind the valves, ready to go. But we have, you know, 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, you know, both digital equipment as well to be able to handle this. So, you know, we're in those discussions for 2026. And so I think we're going to see some further increase in the activity in 26. You know, the oil markets right now and today's oil prices are just kind of holding steady for us, you know, towards the end of the year. But I think that, you know, it'll be gas that shows some uptick next year. And then we'll see what the oil markets do in terms of the price or, you know, 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 you know, later this year and early next year.

Thanks, Andy, for that. 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 crack 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. You know, we don't necessarily work for some of the smaller privates that are private equity-backed that are really know focusing on cash flow or proving out some acreage for a flip we tend to work for the larger companies and especially in oil products and that's been relatively steady for us and so really pleased with what we do for those those companies the level of technology that they operate the efficiencies they get you know 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 know, you may hear different stories from what private equity backed EMPs are going to do, but that's a small exposure for us.

Your next question comes from the line of Steven Gingaro with Stifel. You may go ahead.

Thanks. Good morning, everybody. So I know it's probably early, Andy, and I was curious if you could kind of give me your thoughts when you You gave some guidance on the rig count for the third quarter. 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, you know, you know our view for the year is that you know 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 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 uh i think you know that's that's just all based on you know our our belief in discussions with customers at current oil prices. But, you know, some stability in the fourth quarter wouldn't be a bad thing at all. And so we would certainly welcome that. So we'll see how it plays out.

Thanks. 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, they feel like they're still getting hit with the market, but were 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?

Yeah, so let me explain how we see that and how the market's actually reacting to that and why we're investing in what we're investing in. 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 receipt 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, will 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, you know, 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 rack technologies. That's why we still continue to invest and plan to receive more than 100% natural gas systems later this year.

Your next question comes from the line of Sir Rob Pant with Bank of America. You may go ahead.

Hey, good morning, Andy and Andy.

Morning, Sir Rob.

uh andy maybe i'll ask a big picture question right we've asked a lot of questions on 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 are afraid oil prices may go down right so in that environment andy look in a few months we'll win the budgeting season rfp season for 2026. Right, so as you talk to customers right now, right, what are you hearing, Andy? What kind of oil price do they're going to plan at, do you think they're planning at right now?

Yeah, and so, you know, we think that today's oil price activity can be higher than it is, but because of all the fluctuation in the markets, I'm talking about the oil markets, you know, over the last couple months, you know, 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 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 4 DGBs are all working. We're going into that tender season with that position. I think that it'll 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, aid and change million dollars in other operating income in the drilling services results in the second quarter. Can you just tell us what that is?

Yeah, so on CapEx for 26, we're not ready to kind of give anything with the 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 things. We had an insurance settlement on some equipment damage from, to be honest, a couple 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. You may go ahead.

Hi, good morning. Hey, Keith. Hey, just wanted to follow up on your comments, Andy, on the Emerald fleets. Recognize there's some different technologies built into there, and you mentioned the direct drive resip 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 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's 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've got the cable systems, and you've got switchgear. 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 one or two 18-wheeler trailers of breakers and switch and handling equipment to distribute the power. And so, you know, this is all capital intensive when you get into the power system attached to the electric pumps on the trailers and you know 35 megawatt turbine capital out for that can be in the 40 million dollar range and you know when with turbine technology and turbine power you're also coming up against the demand for you know bigger systems for other industries as well which which everybody's talking about Now, when you move on into turbine direct drive, we run a little bit of that, and we'll use that to boost natural gas demand on some of our Tier 4 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 4 dual fuel, so sometimes the electric's not deployed all by itself. But then we've also started moving to the 100% natural gas resip 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 four 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 six 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 reship, 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 two-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've 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 system. And I think This is where we're moving right now and excited about the potential for this.

Got it. Yeah, very helpful. Are you able or ready at this point, I guess, to give us a bit more color on the run rate of investment in Emerald? You mentioned you've 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?

Yeah, 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 years. This year, we added some more electric emerald as we grew from normal frac to simulfrac and trimal 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 Hines with J.P. Morgan. You may go ahead.

Hey, Mikey.

Hi, Grant. Good morning.

So on the call, you talked a lot about, you know, sort of different tech offerings, but maybe you 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, kind of what customers do you think, you know, are most likely to kind of adopt this offering from you guys?

Yeah, so, you know, in general, over the last year or so, since we rolled this out and been doing this for customers, you know, it's been more the mid-tier customers who have acreage, who have runway and drilling and completions for wells. But at the same time, maybe they don't have, you know, large operational teams. And we can help work with them using our teams that 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 you know, in the Permian Basin, the word's getting out with the ones that we're working with that we are making improvements. And I think that, you know, 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, you know, I'm upbeat about how that's going. You know, in a market like this where it's, you know, 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 to follow up, I think previously, you know, you'd mentioned potentially 15% or so margin uplift from some of these projects and, you know, 20% or so higher revenue content.

uh do you see that being driven more by i guess higher sort of attachment rates of your technology offerings or you know also a combination of efficiencies just from a fully integrated project thanks yeah there's a couple keys there one is a pull through of all the different segments and sub segments that we have when we go to work for these customers and then also you know the upside on the efficiency gains and helping them pull production forward

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

Hey, good morning. Good morning, Eddie. Good morning. So we've seen quite a few oil-directed rigs come out of the US onshore rig count, about 45 rigs or about 10%, which I think is contributing to your 3Q guidance and drilling services. As others have mentioned, 3Q guide and completion services to remain steady was surprisingly resilient. But do we start to see some of the impact of the oil recount declines 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.

Yeah, good morning. So I think let's start with a 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, you know, we talk about 40 plus oil rigs coming out of the market, you know, a large number of those rigs that are coming out of the market are really, you know, the lower technology rigs and rigs that are working for, you know, maybe some of the smaller private equity backed, you know, type private companies that are out there. What you're seeing is, you know, 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 can see some of the smaller private equity backed companies wanting 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 steeper 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. Thank you. 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

you maybe be more inclined to uh perhaps purchase other nat gas resets or gas turbines uh for the distributed power market like like some of your peers have announced in uh in recent quarters just just curious uh around your latest latest thoughts there yeah so you know we're we're holding a good cash position right now really pleased with the cash flow of the company this year and what we're rejecting for the second half and we're really evaluating you know some organic technology growth and uh some of it associated with longer laterals and more efficiencies in the Delaware Basin, some of it associated with, you know, natural gas demand, physical demand in 26 and 27, and some of the discussions we're in. So, you know, 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 Altera acquisition. I think this helps change the profile of the company to a higher return basis. Altera is essentially a product and manufacturing business. And, you know, pleased with that. And we tried to acquire that company seven years ago and were successful a couple of years ago. But we think there's, you know, 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. You know, we may be injecting some more capital in them 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. You may go ahead.

Hey, guys. Thanks for taking my call. Just building off what you said there, Altera seemed like a relative bright spot for 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 in some of the upcoming offshore prospects?

Yeah, if you look back at Altera'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 to gain a little bit of share sometimes in these activity softens. 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 Ultera technology. And so we're seeing that today. And when it's higher technology, it's higher revenue per bit, 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?

Yeah, so I'll address that. You know, in all of our businesses, we're, you know, while we have seen some direct headcount reductions, certainly with activity changes, We're also looking, you know, always at facility consolidation and other areas where we can take cost out of the system. You know, we're even currently undergoing, you know, an ERP conversion where we're taking three that we operate in now and converting to one. 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. All of those efforts continue and will continue as ordinary course stuff.

Your next question comes from the line of Doug Becker with Capital One. You may go ahead.

Thank you. Andy, I was hoping you'd provide a little more color in 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.

Yeah, morning, Doug. Some of that is, you know, as we're seeing some movement in different basins in the third quarter where we've got, you know, 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 and 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.

And 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. You know, leading edge is still, you know, around, You know, low to mid thirties in general, but the interesting thing is we're seeing higher demand for digital products on top of just the assets. And so, yeah, I mean, the assets 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 and Company. You may go ahead.

Good morning, Andy and team. Thank you for taking my question. You mentioned that your Emerald and Tearful 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?

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 two completion. We have a little bit of tier two 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 two 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. Some of the smaller companies that run that and 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 know, 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 dropout over the next year as well.

Okay. Thank you very much. I'll hand the call back to the operator.

Thanks.

Your final question comes from the line of Dan Cutts with Morgan Stanley.

Hey. Thanks for squeezing me in, and good morning. Good morning, Dan. Maybe just staying on that line of questioning around track supply, we'd 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 in 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? Thanks.

Yeah. Yeah, we're at 2.9 now, as you mentioned. If you look at where we were a year and a half ago, we were at about 3.3. We came down to 3. We came down to 2.9. And that's really just by not investing in that older tier two 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 4 DGB working right now. And so with some of the horsepower continuing to drop out over the next year or two, I think it keeps the industry relatively in balance. I mean, 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.

great that's all really helpful um and we've gotten a few anecdotes on this next question but wanted to just kind of ask it more directly so on the on the bundled services and integration patterson has a lot of service lines um and and you know you've made clear that taking more kind of wallet share uh more components of the overall um 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? Has kind of choppiness in the market created opportunities to kind of take more wallet share to, you know, push more Patterson services to your customers, or has it made it more difficult? I know you'd you flagged that digital demand has really been picking up in the big space. But yeah, just trying to think through how kind of pushing the bundled and integrated services has evolved as the macro has evolved. Thanks.

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 P10 advantage package that we offer. And, you know, that investment in digital is keeping us very competitive in a softening market. And that's really important. You know, it's not just about the asset. It's not just about, you know, what we charge for the asset, but what you can do with the asset. And when you layer on, you know, some of the, you know, whether it's the Cortex automation apps on a drilling rig or the new Vertex, automated frac system that 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 P10 advantage package. But given the softening market, I would say that it's harder to show growth 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 and a bit of a softening market right now 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. You may go ahead.

Hey, good morning. Thanks for letting me jump in here. 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, and 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?

Yeah, hey John, this is Andy Smith. You know, look, I mean, that's a constant conversation, right? I mean, it's not... That's not something that is, you know, 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 equipment that can really lead the industry, given the strength of our financial profile, we will, you know, kind of be holding our team's feet to the fire on pricing and saying this is what we're doing. Well, there may be some element of spec to it. We're not doing this entirely on spec.

No, and I'm not trying to throw a curveball because, like, you step back and think about it. A lot of times you hear from folks, you know, that it doesn't, like the spot market, it doesn't really make sense that current returns to reactivate stacked equipment. And, you know, 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 try to change ways. I mean, like, 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, you know, 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 that's where I'm going.

Well, I think, you know, it gets back to bifurcation in the market as well because, you know, we're essentially sold out right now. The Emerald's 100% nat gas systems and a Tier 4 DGB. You know, and there's really not anything that's going to cause me to want to activate a Tier 2 diesel, even though I might have some on the sideline right now. You know, we haven't been investing in it. It's parked. You know, we'll make some accounting judgments on that later, but... uh, you know, we're working everything we've got essentially right now, which is also relatively positive, you know, as we get into the tender season too. And so, you know, I think that, uh, you know, the industry's relatively tight on the higher end equipment working for the hires, you know, uh, you know, the more sophisticated, larger EMPs. And so I think that market is still relatively tight. I mean, it's competitive and yes, the high spec rig counts 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, Lacey. 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.