Patterson-UTI Energy, Inc. (NASDAQ:PTEN) Q3 2025 Earnings Call Transcript

Patterson-UTI Energy, Inc. (NASDAQ:PTEN) Q3 2025 Earnings Call Transcript October 23, 2025

Operator: Thank you for standing by. My name is Rebecca, and I will be your conference operator today. At this time, I would like to welcome everyone to the Patterson-UTI Third Quarter 2025 Earnings Conference Call. [Operator Instructions] I will now turn the call over to Michael Sabella, Vice President of Investor Relations. Please go ahead.

Michael Sabella: Thank you, Rebecca. Good morning, and welcome to Patterson-UTI’s earnings conference call to discuss our third quarter 2025 results. With me today are Andy Hendricks, President and Chief Executive Officer; and Andy Smith, Chief Financial Officer. As a reminder, statements that are made in this conference call that refer to the company’s or management’s plans, intentions, targets, beliefs, expectations or predictions for the future are considered forward-looking statements. These forward-looking statements are subject to risks and uncertainties as disclosed in the company’s SEC filings, which could cause the company’s actual results to differ materially. The company takes no obligation to publicly update or revise any forward-looking statements.

Statements made in this conference call include non-GAAP financial measures. The required reconciliation to GAAP financial measures are included on our website at patenergy.com and in the company’s press release issued prior to this conference call. I will now turn the call over to Andy Hendricks, Patterson-UTI’s Chief Executive Officer.

William Hendricks: Thank you, Mike, and welcome to our third quarter earnings conference call. The performance of Patterson-UTI has continued to demonstrate resilience this year. And our teams have done a great job executing in a challenging environment and staying focused on optimizing our business in the areas that we can control. We are continuing to see success as we enhance our commercial strategies through additional service and product line integration and performance-based agreements, while at the same time lowering our cost structure, which is helping us to lessen the impact from moderating industry activity this year. Headlines over the past 6 months have highlighted cautionary signals, including oil supply growth from OPEC+, shifting demand patterns as trade policies evolve and overall global macroeconomic uncertainty.

But the U.S. shale picture today is more constructive than many expected just a few months ago. Oil prices have fallen, but overall, have so far remained more resilient than many predicted, with long-term global demand growth continuing, and anticipated supply additions slower to translate into physical barrels than headlines have suggested. At Patterson-UTI, while the business environment this year has brought unique challenges, we are adapting with the market, both commercially and structurally, and we continue to generate healthy levels of free cash flow, while still investing to expand our technology edge. Our efforts and focus today center on driving improvements in our outlook for profitability and cash generation against a steady market backdrop.

And each of our businesses are stepping up to this challenge. In the U.S., oil production does not yet fully reflect the impact of activity reductions over the past 6 months. And we believe current industry activity is already below levels needed to hold U.S. production flat. Any further activity reductions from current levels would likely result in additional pressure on future U.S. output, which could negatively impact global oil supply in 2026. On the natural gas side, the outlook as we move into 2026 appears to be favorable. Physical demand growth from LNG is now starting to come online, and our customers are beginning to make plans to satisfy the expected multiyear growth in demand, which is likely to require higher drilling and completion activity compared to current levels.

Even as U.S. shale drilling and completions activity has moderated through 2025, our teams have delivered results that are far more resilient relative to prior periods of activity moderation. Our customers are sophisticated, and they are demanding innovative technologies from both our drilling and completions businesses, which is widening the performance delta among service providers. The increasing reliance on differentiated technologies puts Patterson-UTI in a strong position given the high quality of our operations. We expect this relative margin resiliency to continue as customers rely more on high-end service providers. Operationally, our teams are functioning at a high level in a competitive market. Our drilling team has seen activity stabilize, and our rig count today is slightly above where we were at the end of the third quarter.

Our completion activity continues today at a similar level relative to where we exited September, and we expect completion activity will remain steady for most of the quarter, although typical seasonality is likely to impact the segment during the holidays. As the market steadies, we see opportunities in both our drilling and completions businesses to invest in technologies that are in high demand and short supply, with our expectation that any incremental investments will earn strong returns. As we prepare our 2026 budget, we are working with technology-focused customers on opportunities to deploy new technologies in both drilling and completions, and expanding our competitive edge should widen the advantage we believe we have over much of the industry.

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

Our leverage remains low, with net debt to EBITDA of just over 1x. We closed the quarter with $187 million in cash and an undrawn $500 million revolver. And the fourth quarter should deliver our strongest free cash flow quarter of the year, which should strengthen our capital flexibility as we head into 2026. We will continue to deploy capital only towards opportunities we believe will deliver high long-term returns, including the option to further accelerate our share repurchase program. Our U.S. contract drilling business saw activity stabilize as we exited the third quarter, and we expect this stability to continue through the rest of 2025. Recent revenue per day for drilling rigs remains in the low to mid-30s range. Our directional drilling business is performing exceptionally well, benefiting from strong service quality and new technology deliveries as well as further integrated offerings with both our drilling rigs and our drill bits.

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

The digital and technology package remains a key factor to delivering differentiated solutions for our customers, and the investments we have made have helped margins hold above what our drilling business has achieved in previous periods of activity moderation. Our Completion Services segment demonstrated strong relative performance in Q3, with activity holding steady compared to the second quarter. Our commercial team did an outstanding job managing the frac calendar and aligning us with high-quality customer base, while our operations team executed at an exceptionally high level. Pricing per horsepower hour in our frac business was steady compared to the second quarter, with lower sequential revenue, mostly a function of less sales of low-margin sand and chemical products.

We also started to see benefit of cost reductions in the first half of the year. The completions market remains competitive, but our operational quality is proving to be a major differentiator. We recently set a record for continuous pumping for one of our customers in the Northeast, where we safely pump 348 hours straight on a single fleet. This record highlights the capabilities of our digital performance center in Houston to implement new operating techniques with the support of our local field teams. Our new proprietary EOS completions platform is advancing our technology edge through 3 primary products: Vertex automation controls, Fleet Stream and IntelliStim. This platform will allow us to further implement artificial intelligence and machine learning into the completions process.

After successful deployment in the third quarter, we continue to deploy our Vertex automation controls across all company fleet, with projection for full deployment by year-end. This will allow us to implement closed-loop automation for all pump types to improve our operating efficiency and asset management, while delivering optimized completion designs for our customers based on real-time surface measurements. Fleet Stream will provide data visualization and analytics, a platform to acquire and analyze reservoir measurements and streamline data workflows for our customers and provide a new revenue stream for our Completion Services segment. Finally, in combination we worked on our drilling rigs and through modern machine learning, our IntelliStim reservoir technologies leverage artificial intelligence to provide real-time reservoir insights to better understand rock properties and optimize completion designs to maximize well performance.

We see multiple ways to monetize our digital investments. We are already seeing the investments lower operating and capital costs through higher asset turns. Additionally, on the revenue side, we’ve already signed 2 customers to commercial deals for 2026, specifically for our EOS platform. And we think there is significant revenue opportunity as well as a path to create closer and more integrated long-term relationships with our customers. Our Emerald fleet of 100% natural gas-powered equipment remains in high demand, and we continue to strategically invest in new technologies that are driving accretive returns for the business. We’ve recently taken delivery of our first commercial direct drive pumps, which will allow us to deliver 100% natural gas-powered solutions for our customers with significantly less capital deployed relative to electric frac fleets.

The direct drive pumps are scheduled to begin long-term dedicated work in the fourth quarter. We think recent advancements made in high horsepower direct drive natural gas engines have helped make this the most capital and cost-efficient solution for our business. Our Drilling Products business had another good quarter in North America, where our U.S. revenue per U.S. industry rig set another company record. Since we acquired Ulterra in 2023, we’ve seen a roughly 40% increase in U.S. revenue per U.S. industry rig, with a more than 10% increase in market share for our drill bit products on Patterson-UTI rigs. In Canada, we saw a strong recovery in revenue coming out of spring breakup even as total industry activity was slightly below expectations.

International revenue declined, mainly in Saudi Arabia’s drilling activity in that country slowed. Outside of Saudi Arabia, revenue was strong internationally, and we expect international revenue to increase in the fourth quarter. On the margin side, the quarter did see higher-than-normal bit repair expenses in July, which resulted in lower margins for the quarter, although margins recovered towards historical levels later in the quarter. Our fully integrated PTEN Digital Performance Center located in Houston is the backbone for the entire company. The digital center has been critical as we execute and optimize drilling and completion designs for our customers. The information that we can provide both our team and our customers has improved the efficiency of our operations and brought us closer to our customers as we strive to provide differentiated service.

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

C. Smith: Thanks, Andy. Total reported revenue for the quarter was $1.176 billion. We reported a net loss attributable to common shareholders of $36 million or $0.10 per share and an adjusted net loss of $21 million. Adjusted EBITDA for the quarter totaled $219 million. Other operating expenses for the quarter totaled $23 million, of which $20 million resulted from the accrual of expenses associated with personal injury-related claims for incidents that occurred several years ago, partially offset by a favorable contract dispute resolution. Our weighted average share count was 383 million shares during Q3, and we exited the quarter with 379 million shares outstanding. During the first 3 quarters of the year, we generated $146 million of adjusted free cash flow.

As expected, during the third quarter, we saw working capital benefits, and we expect working capital will be a tailwind again in the fourth quarter. During the third quarter, we returned $64 million to shareholders, including an $0.08 per share dividend and $34 million for share repurchases. Over the 2 full years since we closed the NexTier merger and Ulterra acquisition through September 30, 2025, we have repurchased 44 million Patterson shares in the open market. We have reduced our share count by 9% since that time. This is in addition to reducing net debt, including leases by nearly $200 million, and paying a dividend that is currently an annualized 5% of our share price. In our Drilling Services segment, third quarter revenue was $380 million and adjusted gross profit totaled $134 million.

In U.S. contract drilling, we totaled 8,737 operating days for an average operating rig count of 95 rigs. Geographically, compared to the second quarter, activity was flat outside the Permian Basin, with Permian activity responsible for the sequential decline in our rig count. For the fourth quarter in Drilling Services, we expect an average rig count to be similar to the third quarter. We expect adjusted gross profit will be down approximately 5% from the third quarter. Revenue for the third quarter in our Completion Services segment totaled $705 million, with an adjusted gross profit of $111 million. We saw flat activity on a pump hour basis compared to the second quarter, with margins benefiting from improved operating efficiency and some cost reductions that were initiated in the segment during the first half of 2025.

We saw improved efficiency as several of our larger fleets that saw gaps in the second quarter had more consistent schedules. Additionally, our power solutions natural gas fueling business saw an improvement as natural gas demand in the Permian continues to grow as customers look to take advantage of weak regional natural gas prices by using more of the commodity as fuel. Overall, completions revenue was lower on a decline in sales of low-margin sand and chemicals products. For the fourth quarter, we expect completion services adjusted gross profit to be approximately $85 million, with less seasonality compared to the fourth quarter last year. Third quarter Drilling Products revenue totaled $86 million with an adjusted gross profit of $36 million.

Performance was strong in our U.S. and Canadian businesses, while international revenue was impacted by lower activity in Saudi Arabia, which is our largest international market. Margins were affected by higher bid repair expense in July, although they returned closer to historical levels by the end of the quarter. For the fourth quarter, we expect Drilling Products adjusted gross profit to improve slightly, with relatively steady results in the U.S. and Canada and higher revenue and gross profit internationally. As a reminder, roughly 70% of the revenue in our Drilling Products segment is generated in the U.S., with around 10% in Canada and 20% international. Other revenue totaled $5 million for the quarter with $2 million in adjusted gross profit.

We expect other adjusted gross profit in the fourth quarter to be steady compared to the third quarter. Reported selling, general and administrative expenses in the third quarter were $62 million. For Q4, we expect SG&A expenses will be relatively steady sequentially. On a consolidated basis for the third quarter, depreciation, depletion, amortization and impairment expense totaled $226 million. And for the fourth quarter, we expect it will be approximately $225 million. During Q3, total CapEx was $144 million, including $47 million in Drilling Services, $81 million in Completion Services, $13 million in Drilling Products, and $3 million in Other and Corporate. For the fourth quarter, we expect total CapEx of approximately $140 million. Our full 2025 CapEx is now expected to be less than $600 million, even before considering the benefit of $33 million in asset sales we have realized through the third quarter.

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

William Hendricks: Thanks, Andy. I want to close the call with some comments on our company and the industry. I’m very pleased with our team’s execution in the third quarter, where we are outperforming our competitors in many areas of our market. As well, we continue to make the necessary cost reductions to align the company with the projected levels of activity and maximize long-term free cash flow. This past year has been one of the most unique years since shale emerged as a major source of oil and gas over a decade ago. In many ways, the U.S. shale oil field services industry has outperformed each previous cycle. Our margins are holding up far better than what is typical in periods of activity moderation. Equipment bifurcation and capital availability is leading to disciplined behavior across our industry.

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

There is much to be proud of with the way our teams are operating. But even as the outlook has stabilized, we are not content to simply wait for a market recovery. We intend to stay focused on our plan to maximize the value of our unique commercial model and technology offerings across drilling and completions. And we see evidence that customers are becoming increasingly receptive to more integration and performance-based pricing, as they too search for ways to improve their own returns. We are just at the beginning of realizing the benefits of that journey for the company. The goal for our business leaders is clear. We need to improve our position in the markets where we operate. We are confident that our teams are focused and up to the challenge, and we look forward to proving that out over the next year.

As we start to prepare for 2026, what we see right now is another year of strong free cash flow. Our balance sheet is in great shape, our liquidity is strong, and we are operating with an extreme degree of capital flexibility. Our focus on capital allocation should allow us plenty of opportunities to use our free cash flow to maximize the long-term value for our shareholders, including through a potential acceleration of our share repurchase program. We are pleased with the quality of our operations, and we are confident that we can make our business even better. With that, I’d like to hand the call back to Rebecca, and open up for Q&A.

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

Q&A Session

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

William Hendricks: Listen, I think our teams are just doing a great job out there and executing in the field, some of the really high-end work that we’ve done with large simul fracs and trimul fracs. We’re burning significant amounts of natural gas. We’re delivering that natural gas to location. We’re maximizing displacement of diesel in some cases or on full electric jobs or full Emerald jobs, providing significant amounts of natural gas and fuel savings. And everything that we have to convert natural gas is out and working. And so we don’t feel a lot of pressure to reduce pricing from where we’re at. Now as you know, the industry discussed, there’s been some big tenders over the last few months. Some of those are still in process. But I think, overall, the industry is showing a lot of discipline from where we are right now as well.

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

William Hendricks: Yes, the 100% natural gas direct drive Emerald systems that we’ve just taken delivery of this quarter and just deploying. We’re excited about what we believe is a better use of capital — better allocation of capital and trying to provide 100% natural gas services out in the field. And so we’re excited to have a number of those out working this quarter after shaking that technology down for the last 2 years. When it comes to 2026, we certainly haven’t finalized the budget yet. But what you’ve seen us do over the last several years is invest at the high end without investing at the low end and just letting the lower end of the equipment just move away from attrition. We’ve reduced the overall horsepower we’ve had over the last few years, from 3.3 million at a peak, down to 2.8 million just by letting that lower-tier equipment go away.

And so I think there’s a chance we’ll make some similar decisions next year. We haven’t finalized that yet, but we’re not investing at the low end. And I think that helps keep the market tight. And if we see more demand next year for more of 100% natural gas equipment, we’ll continue to invest because we’re getting good returns on that technology.

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

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

William Hendricks: We have significant technical expertise in power. We have our electrical engineering division that can engineer and manufacture microgrids. On any given day right now, we’re producing around 500 megawatts of power across drilling and completions. We operate generators from 1.1 megawatt recips, all the way up to 35-megawatt turbines. And so we have a lot of technical expertise. But when we look at some of the opportunities as you get into the larger power structures, the AI and data centers are demanding, you’re at the 200-megawatt plus. And some, they’re up to 1 gigawatt of power. That’s not a mobile power solution, that starts to look more like an EPC contract where you’ve had a lot of big construction going on.

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

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

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

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

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

And so our automation controlled software allows us to be able to work across all those platforms and combined situations as well. And we have a number of customers that that’s what they want to do. And so we don’t have any limitations on the type of equipment we’re deploying automation on, and really excited about what that’s going to do for us. It’s certainly a product we’ll be able to charge for. As I mentioned earlier, there’s a number of products coming out of the platform that we believe we can monetize, and this is one of them. It’s going to probably provide some improvement to overall reliability of equipment. It’s going to help us differentiate on how we deploy fracs in the well, and excited about what we can do with it.

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

Saurabh Pant: Great. Good. Andy, maybe I’ll start with a bigger picture question as you talked about macro uncertainty, things seem to have stabilized a little bit where we see where they go from year-end. But as you talk to the customers, Andy, right, be it on the drilling side and the completion side, how does that uncertainty manifest? I’m just thinking on the drilling side, do they want shorter-term contracts to give them more flexibility on the completion side, maybe this more frequent pricing reopeners as an example, right? How are these discussions going, just given the uncertainty in the environment?

William Hendricks: So yes, as we mentioned, activity is stabilized where we’re at right now. The rig count for us has come down this year. And — but the pricing has held up pretty well. There is some pressure. It’s a competitive market, but we’re still in the low 30s on average. And so if you compare that to what has happened in previous cycles of moderation, we’re certainly in a better position today than we have been in the past with an industry. The industry is showing good discipline overall. In terms of what our customers are saying, our customers are trying to keep their production up. And the wells that we’re drilling, while we’re becoming more efficient, are also becoming more challenging, both on the drilling side and the production side.

We’re drilling deeper wells. We’re drilling longer laterals. And our customers are dealing in the Permian with wells that have a higher gas ratio. And so all those things combined to where our customers are trying to keep up the production. And even though we’re in a softer commodity environment right now, they’re trying to keep their production up for their shareholders. And I think that you’re going to see continuing intensity for what we do grow, and we’re getting requests to add more technology to be able to meet the needs.

Saurabh Pant: Right, right. No, that makes sense. That makes sense. And I agree, by the way, with your views on the activity levels. They seem like we are right at or below maintenance level, right? So if you want to keep up your production, you’re going to keep up your activities. Okay. Makes sense. And then a quick follow-up, maybe, Andy Smith, for you on the 2026 shareholder returns. I don’t know you’ll give the framework over time, right? But at this stage, how should we think about share repurchases? It’s good to see you spend that up a little bit this quarter versus last quarter, but just maybe refresh us on the framework as we think about 2026.

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

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

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

William Hendricks: Well, I think that what we’re seeing, where activity is right now, it has the potential to negatively impact U.S. production a little bit. And just voicing that if oil were to stay in the upper 50s for a little while, that probably bring U.S. production down further. And if you’re going to bring U.S. production down further next year, well, the next reaction is, you’re going to have a commodity price reaction. And I think there’d be nervousness in the market. So I think it’d be self-adjusting and self-correcting. So when I think about the long term, I think we’re in really good shape from a fundamental standpoint. We may have some changes in commodity prices over the near term, that may affect some activity levels.

But over the long term, I think the fundamentals are still good. We’re still seeing long-term demand for oil growth over a multiyear period. And the U.S. has to be part of that production as well. It has to be part of that equation. The discussion for OPEC+ to bring on physical barrels, they haven’t really brought as much in terms of physical barrels as has been discussed. And I think that’s baked into what we’re seeing, too. So I think there’s still a balance that we have right now between supply and demand. So — and we see that with some of the decisions that our customers are making too. And like I mentioned before, we have customers that are trying to maintain production for their shareholders, but also balance capital spending in a little bit lower commodity environment.

But we’re staying relatively steady in our activity levels as a result of that. We have customers that are wanting to deploy more technology. They’re willing to pay us for it. And to help them with their efficiencies in how they drill wells and how they complete wells in order to maintain their production.

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

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

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

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

William Hendricks: I think that what you’ll see is that most of us have already gone through a lot of the tenders that you’re having to go through right now. And so what we’re saying for projections in the fourth quarter have kind of already locked in some of that pricing. And there could be a little bit of movement in next year. But as I said, everything that we have that converted natural gas today is sold out, and there’s still demand for equipment that can burn natural gas because our customers are getting a good fuel savings out of that. So I don’t see pricing as a huge headwind. Are things still competitive? Sure. And if there’s any white space in the calendar, which we all know happens from time to time, and we have to fill some dedicated work with some short-term spot work, maybe we take a little bit lower price to do that in the Midland Basin or something like that.

But overall, I don’t see like a huge headwind on the pricing because I think that the work is relatively steady outside of fourth quarter holiday slowdown.

Stephen Gengaro: Great. And the other question just sort of ties into the capital allocation strategy. How do you think about — you obviously have a view on the market, things seem to be stabilizing. But how do you think about capital returns versus balance sheet strength? And what sort of signs do you look for to give you confidence in accelerating or continuing to return capital in a market that has kind of disappointed us for 6 or 7 straight quarters?

C. Smith: Yes, Stephen, this is Andy Smith. So as we look at it, again, our — making sure that we have the equipment in both — in all 3 of our major lines of business that is top of the market is probably the most important thing that we think about when we’re thinking about capital. And then it really becomes what is the cadence of adding that equipment? What is the cadence of making sure that we’re rightsized for the opportunity set that’s out there? What are we looking at beyond that in terms of our balance sheet leverage? I don’t think that we have any issues right now with leverage, to be honest. I’m very comfortable with where we are. And so that hasn’t been as much of a focus, but then we look at the return to shareholders and whether or not we want to over step kind of our 50% commitment to our shareholder base.

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

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

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

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

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

William Hendricks: Derek, so I think there could be, and we’ve had some of those discussions. I think for us, though, the way EcoCell is packaged, it’s designed for hazardous environment operations and drilling. It could fit in a production environment. You don’t need all those qualifications just to put it next to a data center or an industrial application. We’re certainly open and our teams continue to explore those possibilities. Again, when you get into that space of EPC construction and you’re over 200 megawatts and approaching 1 gigawatt of power, you’re competing with a lot of different companies out there. And sometimes, when it’s an EPC project like that, it’s big, the winner is essentially the lowest bidder, and that doesn’t necessarily bring value for us.

And so we’re going to focus on things that we think can produce strong free cash flow. So it’s designed for as well as a variable load because drilling rig surges as you engage the draw works or you engage the pumps in ways that industrial applications don’t see. And so we’ve written custom software to manage that. So it’s just a little bit of a different configuration and setup versus what you do for industrial applications.

Derek Podhaizer: Got it. That’s very helpful. I wanted to ask a question around drilling. So you talked about Permian being a soft spot here, but obviously pockets of strength, specifically in the gas basin. So just thinking about the rig count, it’s up a little bit from where you are, you’re going to be steady. If you think about the upside to rig count next year, whether that’s gas or even the Permian recovering, how should we think about the required OpEx or CapEx invested back into these rigs that have been sidelined? And just thinking about what that could mean for the future margin expansion once we’ve rolled through all this contractor and all this pricing and then you’re on actually I’m going to reinvest back into these rigs that have been sidelined for quite some time now. Just maybe some updated thoughts how we should think about that with your rig count today.

William Hendricks: Yes. We haven’t done any of that math recently, but I can tell you, historically, when we reactivated a rig, it’s been several million dollars to get a rig reactivated from a capital standpoint. And so we would take that into account any agreement that we’re working out. But the other is that as we have some of these discussions with E&Ps for what they’re going to need over the next couple of years, they’re also wanting more technology on the rig, more capacity on the rig, longer laterals, deeper Haynesville gas, things like that. And so that’s going to drive some larger conversations, but it’s also going to drive larger day rates. And so we will look at them on a project by project basis like we always do when we restart a rig. And if we’re adding more technology than we normally would or we’re doing structural upgrades, then we’ll get paid for that at a high return as well.

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

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

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

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

William Hendricks: Yes, we could talk about a few of those points. So first, the easy one is structural. So as we drill deeper wells in the Western Haynesville with the laterals that they’re drilling, the casing loads are getting bigger, so the structural capacity is moving up from, say, what we’ve had over the last decade, which has been a 750,000-pound rig in general for the industry, up to 1 million pounds. And so we’re seeing those request for the structural upgrades. But we have E&Ps that are wanting that as well for the Delaware where we’re drilling deeper and longer laterals and they’re using more drill pipe and they want to stay efficient, not have to lay down the drill pipe. So they want that structural capacity to be able to rack back more pipe just for those efficiencies in the Delaware.

So it’s a combination of the 2 and for those different plays, but it’s a similar rig style and similar engineering that we have to do for that as well. The other piece is automation. I’m really excited about what’s happening in the areas of automation and what our teams are doing with artificial intelligence. I’ll just let everybody know, we had an update with the Board this quarter on all the different artificial intelligence projects that we’re doing in the company, and we’ve let those grow up from our engineering teams and drilling and completion, and excited about the way they’re looking at things. And when we say artificial intelligence, for us, it’s not necessarily your traditional large language model that everybody uses on a daily basis.

We do a lot with artificial intelligence and machine learning. And we feed data into our systems from our data science teams to allow our models to learn how wells have been drilled so that we can take that forward into the field and deploy those automation and machine learning models onto the equipment, whether it’s drilling or completions, and so that the equipment can now function at a higher level with more efficiency, which improves reliability, longevity of the equipment and also brings benefit to the E&Ps as well.

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

James Rollyson: Andy, you’ve been through a lot of cycles and I think you’ve talked about a little bit on this call, this cycle has definitely been a bit different than typical cycles. And in that, I’m kind of curious, as you think through ’26, ’27, historically, we come down in a pretty violent manner. And when U.S. land balances, it kind of comes from both drilling and frac, and you ultimately get pricing leverage again after you’ve had — they go in the wrong way for you. And this cycle has kind of played out differently in that pricing has held up better, there’s a lot of technology you’ve kind of discussed. And I’m just curious, as you think through once we hit the bottom and the gas rig count starts to go up and oil rig count eventually starts to recover to replace production, how do you think about how this cycle unfolds?

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

William Hendricks: Thanks, Jim, and thanks for reminding me that I’ve seen a lot of cycles. I appreciate that this morning. Yes. This one has been an interesting one where it’s really been about 2.5 years of activity coming down across drilling and completions for various commodity reasons. And so we’ve had to look and say, okay, what’s happening next, how do we adjust the company and the structure for where we are, where we think it’s going. And we continue to do that. So even though we’re saying we think activity is relatively steady from here, we continue to look at the structure of the company and make sure we’re rightsized for where we are and where we’re going. With it coming down in the pattern that it has this time, I think there’s a chance that the reverse look similar, but there could be a little bit quicker inflection on the gas side.

But either way, we see upside from where we are, whether it’s continuing to adjust our company for where we are in the market or upside from gas activity later in ’26 and ’27, we still see upside. So we think we’re in a great position. We’ve got strong balance sheet, lots of flexibility with the cash and continue to deploy technology and get paid for it. And so even though it’s — we’re in this — what do you want to call it, a softening market or moderating market or however you want to describe it over the last period, we’re still upbeat about where we are and where the company is in the market.

James Rollyson: Got it. That’s helpful context. And then maybe lastly, just on the kind of digital suite that you laid out in the completion side that you’ve already started putting on, and I think you mentioned every fleet will have it by the end of the year. Maybe some goalposts around what is like the revenue and profit opportunity in that space if you get a high rate of customer adoption? Just when you think about how that maybe offsets the general activity trend that we’ve seen as we go forward.

William Hendricks: Well, I think it’s still early days. And on the completion side, we’re still signing some contracts to do that and providing those digital services for next year. On the drilling side, it’s millions of dollars a year in revenue that we’re generating off the digital. We rolled out our Cortex operating system years ago, and we continue to add applications to that on the drilling side. And now those applications, through our data science team, are incorporating artificial intelligence, will be layered into those as well. And so that’s just going to enhance the productivity of those applications. So I think it’s still early days in the technology journey. We’ve built out the infrastructure. For those of you that have come to see our PTEN Digital Performance Center, you know we’ve made the investment.

We’ve got the platform. And so now we’ve got teams that are building on top of that. And we’re talking software. This is not heavy capital in terms of an investment, but yet there’s revenue upside for us.

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

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

William Hendricks: It’s around that 250,000 level right now. We’ve still got some more of those Emerald 100% natural gas that are being delivered this quarter. We’re deploying them this quarter and still have some more coming in, but it’s still around that level. In the overall horsepower, which I think is even more interesting. Like I mentioned earlier, we had, had as much as 3.3 million, but we brought that down to 2.8 million. And I think there’s others in the market that are doing similar. And that’s why I’m constructive on the market for completions and pressure pumping just because I think that overall horsepower continues to come down in the market.

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

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

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

William Hendricks: Sure. Let me just explain it this way, and I’ll give you some high-level round numbers on it. So our Emerald electric is performing really well in the field. We have customers that want to use that. We actually grew the amount of horsepower in our Emerald electric this year because we had customers that wanted to move from standard frac size to simul-frac and trimul-frac with the electric. When we do that, you also have to increase the power supply at the well site. And so we’ve gone from, for instance, on one job, a single 35-megawatt turbine up to a 35-megawatt turbine and combine it with some smaller turbines as well to generate enough power to run larger frac spreads than what we would normally do with a 35-megawatt turbine.

The turbines are expensive. 35-megawatt turbine is generally talking about capital costs deployed in the field in the $40 million to $45 million range. And then when we put the smaller turbines out there as well, you’re in the $15 million to $20 million range per turbine. So you’re talking about a lot of capital costs tied up just on power, and you’re also competing in the market for that power with everything that everybody else has talked about and where power is going to go over the next couple of years. So it’s not just capital costs, but you’re competing for those types of power-generating devices as well. When we look at the 100% natural gas to drive engines, and these are high horsepower engines, 3,600 horsepower. So it’s a new technology that’s being deployed versus other technology that may have been deployed in the past couple of years.

We’re excited about this. This is a great supplier, a well-known manufacturer of the engines and the transmissions and then we spec out the rest of it, including our own control systems on it. And we think that with our control systems on it, we can help manage it. When you look at the overall capital cost versus an electric with the turbines, I don’t have the actual numbers and differentials in front of me, but it’s certainly lower. Our teams have done all the work on that. When you look at the OpEx, the OpEx for a natural gas director of engine is going to be higher than in diesel, but the overall OpEx or 100% natural gas direct drive engine, in our projections, is lower than trying to maintain both electric pumps and the turbine generators at the same time.

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

Daniel Kutz: That was very helpful.

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

Sean Mitchell: Can you hear me okay?

William Hendricks: Yes, Sean.

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

William Hendricks: So we haven’t idled any fleet per se. And the way — the best way I can describe that is quarter-on-quarter, we’re still working the same amount of horsepower pumping similar horsepower hours in field, but we’ve grown some fleets to do more simul-frac and trimul-fracs. So there’s been a shuffling of horsepower around to different places. The fleet count, at the end of the day, is really kind of hard to judge. It’s not such a great metric because of the fluctuation in fleet size as we do more simul-frac and trimul-frac. And I think you’ll see companies like ourselves where the actual horsepower per fleet grows a bit because we’re doing higher intensity fracs. We’re doing more volumes on pads, things like that. So — but we — to sum it up, we are working the same amount of horsepower, pumping similar horsepower hours quarter-on-quarter. So we didn’t really stack any technology.

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

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

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

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

Donald Crist: Andy, I wanted to first applaud you for sticking to your guns and which I’ll do is a core competency, and not chasing the latest fad as some of your competitors, including very large competitors are doing. But in that vein, I kind of wanted to ask a question about M&A. We’ve seen a lot through the E&P side and investors keep on asking all the analysts, is there going to be another wave of M&A on the oilfield service side. And a lot of us don’t really see it. But do you see some of your larger competitors that are chasing the power side actually freeing up some of that equipment that could be attractive to you all in the future, to where you could, number one, stick to your core competencies, but go into another kind of M&A transaction that would be accretive in the future, possibly overseas?

William Hendricks: Okay. There were several different questions in that one, but let me try to take some of that. So first off, I’ll say, we don’t have to do any M&A. We’re really happy with where the company is today, the cash production profile that we have with the company, the technology deployment that we’re doing. So there’s nothing that we need to do. We’ve got great segments that are doing great work and strong competitors in the market today and leading in a lot of areas. So happy with what we have. In terms of some consolidation, I think that, let’s say, on the completion side, there’s probably still some room for some smaller companies to get together. And I think that would shore up some of the completions market if that happens over time.

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

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

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

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

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

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

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