Good morning. Thank you for standing by. My name is Prilla and I will be your conference operator today. At this time, I would like to welcome everyone to the Patterson-UTI Third Quarter 2024 Earnings Conference Call. Thank you. I would now like to turn the conference over to Michael Sabella. You may begin.

Thank you, operator. Good morning and welcome to Patterson-UTI’s earnings conference call to discuss our third quarter 2024 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 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.

Thanks Mike. Welcome to our third quarter earnings conference call. It’s been one year since our first earnings call after acquiring Ulterra and merging with NexTier, and the year has been transformative for Patterson-UTI. These strategic moves have solidified our position as a leading player in the oilfield services sector. Despite a challenging macro environment including fluctuations in oil and natural gas prices and shifting industry activity across key basins, we have successfully integrated NexTier and Ulterra. All of our segments are performing well given the backdrop, and we have stayed focused on operational excellence for our customers and free cash flow for our investors. We believe that the progress we have made in just one year will create value over the long term for the company and for shareholders. I want to extend a sincere thank you to all of our employees whose hard work and dedication have been crucial to the success of the integration. We could not have done it without you, and we are grateful for your contributions in making this process smoother and more efficient. We believe we’ve only begun to unlock the true value of our company. There are many opportunities to further integrate our operations, and we are just starting to realize the potential commercial synergies. Our integrated approach across the entire drilling and completions process is strengthening relationships with a broader customer base and positioning us for long-term success and strong financial returns. Even in a challenging market, we think there’s still room for capital-efficient profitable growth for Patterson-UTI. In the first four quarters since the transaction closed, we generated almost $570 million of free cash flow. We have used that free cash flow to make $346 million of share repurchases while paying a steady dividend and reducing our net debt, including leases. The total cash returned to shareholders through share repurchases and dividends amounts to 15% of our current market cap, while our net debt, including leases, is down by 7%. This past year has showcased Patterson-UTI’s resilience and strength through different points in the cycle. We always recognize that there can be fluctuating demand for our services and our combined size, scale and broad service offerings position us well to compete in any market. On our previous earnings call, we shared exciting news that we had entered into our first fully integrated drilling and completion arrangement under a performance-based agreement. This customer is using a broad suite of our products and services across an entire pad, marking a new chapter in how we deliver value. As shale evolves, we believe companies with differentiated business models will be best positioned for premium returns. As one of the largest drilling and completion companies in U.S. shale, we are confident in our ability over the long term to deliver best-in-class results to our customers while driving accretive returns for our investors. The results have been very encouraging. Both our customer and Patterson-UTI are benefiting from this integrated approach. We are on track to complete the path ahead of schedule and expect accretive returns relative to our overall business. Our unique commercial strategy is being noticed by the market, and there are several potential new customers that are paying close attention to the success of our integrated approach. We are in discussions with other potential customers for a similar concept, and we think this commercial strategy could have significant upside. The wellsite integration opportunities will be enabled by our cutting-edge PTEN+ Performance Center, where our customers along with our teams will be able to digitally track their full pad from start to finish. This is truly shaping up to be a win-win situation, and we think this commercial strategy has the potential to bring significant value to our customers and our investors. Rather than reacting to the market, we are anticipating its direction and positioning our company to lead shale into its next phase. On the macro front in drilling, we expect to see a relatively steady rig count for our Tier 1 high-spec drilling rigs through the rest of the year and into 2025 based on our contracts and also based on our large customer programs. However, at the same time, the overall industry rig count may fluctuate as older lower-spec assets could see weaker demand from smaller E&Ps. In completions, we expect customers will continue to flex activity to maintain spending within their budget, which is likely to impact frac activity through year-end before recovering in the first half of 2025. On the natural gas side, we’ve seen commodity prices somewhat stabilized recently, reinforcing our optimism about the long-term outlook for natural gas activity. While it will take some time for the natural gas market to fully rebalance, we think the market is stabilizing and should have some upside at some point in 2025 as domestic demand rises and LNG takeaway begins to come online. On the oil front, we observed a slight softening of activity during the third quarter, primarily driven by customer-specific M&A and ongoing natural gas takeaway constraints from the Permian Basin. Going forward, we expect all activity will remain steady into next year. Over the past couple of years, our customers have been less responsive to fluctuations in oil prices, which has reduced the cyclicality of our business. When oil prices declined towards the end of the third quarter, we did not see any change in customer plans, and we do not expect our customers to change their plans absent an extended move in the commodity relative to what we have seen recently. This stability has been an advantage as we make long-term plans for our business, and we have maintained a disciplined approach to capital deployment. Even in the challenging market we have seen in the second half of this year, we are generating strong free cash flow. Looking ahead, we anticipate average activity in 2025 will be slightly below 2024, with our rig count essentially steady from current levels. There is some potential for modest improvements in natural gas markets later next year, although we are not planning for it at this time based on industry LNG facility delays. We are working to ensure that the company has the appropriate cost structure for this environment. We think there is room for Patterson-UTI to capitalize on future opportunities as the market evolves while still generating strong free cash flow. We are committed to returning cash to shareholders. In our Drilling Services segment, we saw a slight reduction in our rig count early in the third quarter, mainly due to customer M&A in oil basins. Our natural gas drilling activity saw a slight increase as the quarter progressed. Once again, our adjusted daily gross margin exceeded expectations. Revenue per day continues to remain stable while we continue to focus on our cost structure, demonstrating our commitment to return on capital even in a challenging market. In the U.S., we began the fourth quarter operating 107 rigs and are currently operating 105 rigs. We believe our rig count is likely to remain steady through the rest of the year with steady activity in both oil and natural gas basins. For the industry, we see the potential for the overall rig count to move somewhat lower, while at the same time, the industry continues to move towards Tier 1 rigs. This provides a steady level of activity for our company compared to the overall industry. We believe we operate one of the highest quality rig fleets in the U.S. In Completion Services, revenue was up slightly sequentially as we saw a mix shift towards more integrated services. Although we did see some unplanned gaps that impacted fixed cost leverage and caused the segment adjusted gross profit to decline sequentially. Natural gas completion activity was up compared to the second quarter. We anticipate that completion activity will decline sequentially in the fourth quarter on a combination of the usual holiday seasonality and also slowing completion activity as customers look to maintain their budgets. We continue to see strong financial results from our electric fleets that have been fully deployed, which are delivering higher-than-average returns compared to the Completion Services segment average. We should see the percentage of pump hours generated by our electric frac equipment to increase again in the fourth quarter. Even as we recently lowered our 2024 CapEx expectation, we increased our electric horsepower to 155,000 in the fourth quarter as we continue to high-grade our fleet. In the year since we merged the completion businesses of NexTier and Patterson-UTI, we are pleased with our performance during this time given industry trends. We have maintained capital discipline relative to our peers while also upgrading our fleet, and this has contributed significantly to the strong free cash flow generation of the company. We believe our entire fleet of horsepower is one of the highest quality in the industry with approximately 80% being able to be powered by natural gas. Over the past year, we have made significant investments in our business to secure future work while simultaneously delivering strong free cash flow for our investors. This dual focus on technology growth and financial discipline underscores our commitment to enhancing shareholder value in a competitive landscape. Results in our Drilling Products segment remained strong with revenue in the U.S. improving sequentially even as the industry rig count declined. In addition, the team has done an excellent job outperforming the broader market through superior customer service. Over the past year, one of the most exciting developments has been the coordination between our Drilling Services team and our Drilling Products team. Since we closed the Ulterra transaction last year, the market share of our drill bits on our own rigs has increased by more than 10%, which shows a strong industrial volume to this M&A. We think there is still significant upside as we see the opportunity to deliver a unique product to our customers. On the international front, we are also excited to have signed a previously announced joint venture agreement in the UAE with subsidiaries of ADNOC Drilling and SLB. We will hold a 15% interest in a newly created company named Turnwell Industries, which has been awarded a contract to drill and complete 144 unconventional wells for ADNOC. We will provide expertise as ADNOC begins what we believe will be a groundbreaking project that could result in multiple years of unconventional drilling and completion activity, and our participation allows us to gain a valuable presence in the region with a limited capital contribution.

Thanks, Andy. Total reported revenue for the quarter was $1,357 million. We reported a net loss attributable to common shareholders of $979 million or $2.50 per share in the third quarter. This included an $885 million impairment of goodwill, a $114 million asset retirement charge and $7 million in merger and integration expenses. Excluding the goodwill impairment, asset retirement charge and merger and integration expenses, our adjusted net income would have been $2 million. Adjusted EBITDA for the quarter totaled $275 million, which also excludes the previously mentioned special items. Our weighted average share count was 392 million shares during Q3 and we exited the quarter with 390 million shares outstanding. As previously noted, during the third quarter, we reported an $885 million charge related to the impairment of goodwill that was recorded with the NexTier merger. The merger was a stock-for-stock transaction that was negotiated at a 0 premium to the market price of a share of NexTier at the time of the deal announcement on June 15, 2023. The recorded equity consideration was based on Patterson-UTI’s share price at the time the transaction closed on September 1, 2023, which was 34% higher relative to the announcement date. This higher share price resulted in higher recorded equity consideration, leading to the recognition of goodwill from the transaction, the goodwill impairment related to our Completion Services reporting segment. On a periodic basis, we evaluate our fleet of drilling rigs for marketability based on the condition of inactive rigs, expenditures that would be necessary to bring in active rigs to working condition and the expected demand for Drilling Services by rig type. The components comprising rigs that will no longer be marketed are evaluated, and those components with continuing utility to our other marketed rigs are transferred to other rigs or to our yards to be used as spare equipment. The remaining components of these rigs are retired. In the third quarter of 2024, we identified 42 legacy non-Tier 1 rigs and equipment to be retired. Given our updated view on the outlook for industry drilling activity in the U.S., we believe these rigs have limited commercial opportunity and are unlikely to ever return to work with our significant capital investment. We recorded a $114 million charge related to this retirement in the third quarter of 2024. During the first 9 months of the year, we generated $322 million of free cash flow, with more than $100 million generated in the third quarter. During the third quarter, we returned $71 million to shareholders, including an $0.08 per share dividend and $40 million used to repurchase more than 4 million shares. In the fourth full quarter since we closed the NexTier merger and Ulterra acquisition, we have used $346 million to repurchase shares. This is in addition to reducing net debt, including leases and paying a steady dividend. Our cash returned to shareholders in the first full quarter since the NexTier merger and Ulterra acquisition closed totaled 15% of the current market cap, while our net debt, including leases, over that same time is down 7%. We have lowered our share count by 7% over that same time period. In our Drilling Services segment, third quarter revenue was $422 million and adjusted gross profit totaled $171 million. In U.S. Contract Drilling, we totaled 9,870 operating days. Average rig revenue per day was $36,000, with average rig operating cost per day of $19,900. The average adjusted rig gross profit per day was $16,100. We continue to see a relatively steady revenue per day with mostly steady recent pricing for our top-tier assets. We also saw a sequential improvement in our cost per day during the quarter. On September 30, we had contracts for drilling rigs in the U.S. providing for approximately $401 million of future day rate drilling revenue. Based on contracts currently in place, we expect an average of 58 rigs operating under term contracts during the fourth quarter of 2024 at an average of 33 rigs operating under term contracts over the 4 quarters ending September 30, 2025. In our other drilling services businesses besides U.S. Contract Drilling, which is mostly International Contract Drilling and Directional Drilling, third quarter revenue was $66 million with an adjusted gross profit of $11 million. We saw an improvement in our Directional Drilling results compared to the second quarter, driven by market share gains and higher margins. For the fourth quarter in U.S. Contract Drilling, we expect to average 106 active rigs with adjusted gross profit per operating day of slightly less than $15,000. The reduction in margins is a function of contract churn in the drilling business as our contract book continues to reset to the current market rate. However, we are encouraged by the resiliency of recent term contract rates. Aside from U.S. Contract Drilling, we expect other Drilling Services adjusted gross profit to be down slightly compared to the third quarter. Revenue for the third quarter in our Completion Services segment totaled $832 million, with an adjusted gross profit of $128 million. We saw a slight increase in revenue on a shift towards more jobs with additional completion-related integration services. However, several of our fleets experienced unplanned gaps, which impacted fixed cost leverage on those fleets compared to the second quarter. The higher revenue was mostly a function of an increase in activity in natural gas basins relative to the second quarter. During the fourth quarter, we expect to see lower pumping hours compared to the third quarter as our customers flex completion activity to maintain spending within their budgets, while there is also additional downtime associated with normal holiday seasonality. For the fourth quarter, we expect Completion Services adjusted gross profit to be approximately $85 million. We believe the Completion Services segment is likely to see higher adjusted gross profit in the first half of 2025 relative to our expectations for the second half of this year. Third quarter Drilling Products revenue totaled $89 million, which was a 4% increase sequentially. Adjusted gross profit was $42 million. The higher sequential improvement in revenue was mostly the result of the resumption of normal activity in Canada following normal spring breakup. In the U.S., we saw higher revenue and margins even on a lower U.S. industry rig count as our U.S. operations continue to see strong share gains in margins. For the fourth quarter, we expect a slight sequential increase in Drilling Products revenue and adjusted gross profit compared to the third quarter driven by growth in our international business, while revenue in the U.S. business is expected to decline slightly on a lower industry rig count. Other revenue totaled $15 million for the quarter with $5 million in adjusted gross profit. We expect other fourth quarter revenue and adjusted gross profit to be flat with the third quarter. Reported selling, general and administrative expenses in the third quarter were $65 million. For Q4, we expect SG&A expenses of approximately $65 million. On a consolidated basis for the third quarter, total depreciation, depletion, amortization and impairment expense excluding the goodwill impairment totaled $375 million, of which $114 million was from the previously mentioned drilling rig asset retirement. For the fourth quarter, we expect total depreciation, depletion, amortization and impairment expense of approximately $255 million. During Q3, total CapEx was $181 million, including $69 million in Drilling Services, $87 million in Completion Services, $16 million in Drilling Products and $8 million in other at corporate. For the fourth quarter, we expect total CapEx of roughly $150 million, which brings our full year CapEx expectation to around $690 million. We are proud of the way we have managed our CapEx in 2024, and our CapEx this year is expected to come in materially below our original budget. Yet we are exiting the year with more next-generation electric horsepower than what we expected in the original budget and one of the highest quality drilling rig fleets in the industry. We will continue to make targeted investments in next-generation equipment across all our businesses while also maintaining a strict focus on capital discipline. We closed Q3 with nothing drawn on our $615 million revolving credit facility as well as a $115 million in cash on hand. We do not have any senior note maturities until 2028. All three rating agencies have recently affirmed our investment-grade credit rating. The investment-grade rating allows us to maintain a lower cost of capital, and we are focused on managing our capital structure in a way that protects our credit rating. We expect to generate another quarter of strong free cash flow in the fourth quarter. We still expect approximately 40% of our adjusted EBITDA to convert to free cash flow in 2024, including customer prepayments we received in 2023 for work performed in 2024. Our Board has approved an $0.08 per share dividend for Q4. Year-to-date through the third quarter, we have returned $366 million to shareholders, consisting of $270 million for share repurchases and $96 million for dividends. After we pay our dividend in Q4, we would have reached our goal to return at least $400 million to our shareholders in 2024. We are continuing to explore all uses of cash, including the option to further accelerate our share repurchases.

Thanks, Andy. I want to close on a few key takeaways. First, we’re excited about the service and product capabilities that we now have at Patterson-UTI, and are proud of the teams for all they have accomplished over the last year to integrate the businesses and work together. We have created an important company in the oilfield services market, which has an unparalleled offering in drilling and completions. On the macro in Q4 in Contract Drilling, I expect that the overall industry rig count will see some declines in the fourth quarter as smaller E&Ps slow for year-end before possibly increasing in the first half of 2025. While at the same time, our Patterson-UTI Tier 1 high-spec rig count will be relatively steady. This is primarily due to the larger drilling programs that we are involved in and the continuing high grading of industry rigs to Tier 1 high-spec rigs. In our Completions business, while the fourth quarter shows a seasonal slowdown, we do not think this is an accurate representation of the way the market will take shape throughout 2025. As we move through negotiations for work in 2025, there are many things that we believe are working to our advantage. We think our top-tier assets are positioned to remain well utilized, even as the lower end of the industry fleet continues to fall off. Given the higher capital intensity on the average fleet, there is likely to be very little spare capacity in the high-end natural gas-powered portion of our fleet. Said simply, the completions dynamic in Q4 is not indicative of the frac demand setup for 2025, and demand for the high end of the frac fleet could tighten as we move through 2025. As I previously mentioned, even though we have not worked through a budget process for next year, we believe that the average activity levels in 2025 in the U.S. could be slightly lower than the activity in 2024, and with the rig count essentially stable from where we are today. As such, we will ensure that the company is appropriately structured for the level of activity. I anticipate that total CapEx for 2025 will be lower than our 2024 CapEx, and we will continue to invest in technologies where we get higher returns. We are focused on cash conversions in each of our segments. We are rationalizing our asset base and are no longer investing in certain assets that we do not believe will be competitive going forward. We have retired 42 rigs that have been idle for more than three years. Additionally, we are retiring and decommissioning nearly 400,000 horsepower of older Tier 2 diesel frac equipment this year. And even with the new build electric equipment, we will have reduced our completions fleet by about 10% to 3 million horsepower by year-end. We do not see a path to making a return investing in these uncompetitive assets for Patterson-UTI or even for other players in the industry. Therefore, we are taking a leadership role to reduce the supply of equipment in what is currently an oversupplied market. At Patterson-UTI, the benefits of size, scale and integration are apparent in our ability to deliver best-in-class service to our customers. As our customers become more focused on data and make database decisions, we are increasingly optimistic that service quality and depth of offering will be a heavy driver of contractor selection, which should be a tailwind for our Drilling and Completions wellsite integration program. While the low-hanging fruit from NexTier and Ulterra transaction has been realized, there are still significant operational and commercial synergies remaining, and we are just starting to realize the full benefit of our capabilities. We have a strong balance sheet and an investment-grade capital structure, and we expect to continue to deliver strong free cash flow while also advancing our technical capabilities. We will continue to use our capital to look to drive incremental returns for our shareholders, which could potentially include accelerating our shareholder repurchases. With that, we’d now like to open the lines for Q&A, and I’ll hand it over to Perla.

Your first question comes from the line of Scott Gruber with Citigroup. Please go ahead.

Yes, good morning.

Scott, good morning.

Hey, Andy, you mentioned higher gross profit in the first half of next year for Completion, which seems very reasonable given the kind of exaggerated seasonality you have here in 4Q, and certainly aligns with your flattish drilling activity forecast. But just thinking about where the run rate kind of profit margins for the business lands early next year, can you provide any color on where you think that lands? I realize there’s a lot of moving pieces today, so feel free to provide a range. But curious whether you can get back to the 3Q level of profit next year after we work through the seasonality? So kind of thinking about 2Q next year, can you get back to what you guys just printed here in 3Q?

Yeah. Thanks. So as we look at Q4, we certainly are seeing a reduction in the activity. But as I mentioned, we don’t think that’s indicative of what’s going to happen next year. We think that the start of the year brings a reset, and I think you’ll see, especially for our Completions business, a lot of equipment go back to work. And I think the pace of that is still not clear, but we do think over the first half of the year, it’s going to move back up to where we’ve had it kind of mid-year this year. So we think it’s relatively steady after that ramp-up as well. So in terms of margin and profitability, we’re certainly looking at the structure of the company. As I mentioned, we believe that the overall setup for 2025 in activity is slightly lower than what we’ve seen in 2024. And we are looking at the structure of the company, and we’ve already made some moves on that. So we do think that there’s certainly lots of room to improve profitability over what we’re going to see in Q4 because that’s really an anomaly with the customers that are slowing down for the quarter. So profitability in the margins will move up, and we’re certainly going to target margins that we had kind of mid-level of this year.

I appreciate that. And I just wanted to turn to the Turnwell JV, it’s certainly a very interesting development. And it sounds like your participation is going to be somewhat modest here near term. But can you provide some color on how you’ll be participating near term? Is that just advisory? I don’t believe you’re contributing rigs or pumps, but is there an opportunity to pull through bids? And then longer term, would you look to have your participation evolve? Would you aim to provide rigs longer term? So just some more color on the JV, that would be great.

Yeah. So, we’re really excited about the opportunities with this JV. We’re excited to participate in this project, which is moving the needle for production for ADNOC over time, over the long term as they seek to develop their unconventional resources. I’m pleased that they wanted to work with us as a partner in this process. So we’re initially providing expertise, which we’ve already started to move some people over in that direction since signing the JV to plan to go forward. And so for now, it’s going to be expertise, and we’ll slowly add people into that system over there to help them with their program. There’s already a number of rigs that ADNOC Drilling owns that are currently working on the project. They are in discussions to increase the rig count. We may be a part of that. But one of the tenets of what we’re doing in international markets is to be very careful with how we’re deploying capital. The capital that we spend for growth has to clear the hurdle of simple things like buying back our own shares and other opportunities we may have in the U.S. And so if we move rigs over there in that direction, it will be because it makes sense from a capital deployment standpoint. And also, it doesn’t impact our plans to return cash to shareholders, which is our primary focus. So I would say that there could be that potential for us to do that. But we’re still working through that at this time, and our priorities are still returning cash to shareholders.

Thanks, Andy. I’ll turn it back.

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

Thanks. Good morning, everybody. I think two for me, but maybe I’ll start. You talked about retiring some frac, some older frac horsepower. And when you think about sort of the supply/demand for pressure pumping, and you mentioned it’s a bit oversupplied right now. How do you think about like the medium term sort of ‘25, ‘26, the type of attrition that you expect to see and kind of where maybe older versus new equipment fits in? And is there a way kind of how you gauge what industry attrition should look like to kind of get us back closer to balance?

I think overall, the industry is seeing attrition. We wanted to get out there and take a leadership role in making these announcements and saying that, look, we are taking out approximately 400,000 horsepower of the older equipment. At the same time, we’ve added at the high end of the spectrum with newer electric equipment. And so we think that this is prudent for us, it’s prudent for the industry, and we expect others to do similar. I think that it depends on where you’re working and the type of work you’re doing. But if you’re doing spot work in the Midland basin, you’re probably not making enough returns to actually maintain your equipment. So you’re naturally getting attrition at the same time from that. When you’re like us, you’re working on some of the larger programs for some of the bigger customers. We are maintaining our equipment, but it’s going to be, in general, higher-end equipment. We have used some of that Tier-2 equipment from time to time during the year, but we didn’t reinvest in the maintenance. And we just consumed it as we used it. And so that’s how we see it. I think we will – if we’re in a relatively flat market, which we believe we’re going to see next year with a little bit of overall activity down, we’re still going to use a little bit of Tier 2 here and there in the mix of our fleet, but we won’t reinvest in it and we’ll continue to consume it next year. And I think you’re going to see the same from other companies as well. So I think overall, what you’re seeing in the industry is near zero investment in that equipment because we’re certainly not investing in it. And I think it’s only the smaller players that own some that would continue to invest. The other thing you’re seeing is a continued trend to higher amounts of horsepower per fleet. We’re doing more simul-frac, we’re doing the occasional trimul-frac, and that’s consuming horsepower as well. And so when you look at the overall industry activity, these kind of activities are amassed with more of the larger pressure pumping companies doing more simul-frac and occasional trimul-frac. And so I do believe that in 2025, it is going to be a tight market. We’re not going to invest in the older equipment, so it’s not going to be available to help fill in on some of the fleets when it might have been in the past, and it’s going to cause a tightness from that standpoint. You’ve got higher amounts of horsepower per fleet with the larger programs. And the primary driver is natural gas. People want to use natural gas. And essentially everything that we have that can burn natural gas is working. So that’s how we see it. And I do think the market tightens as we work through 2025, even in a relatively flat market once we get going again in the New Year.

Yes, Stephen. I would add to that. But again, I think Andy said it right, that with higher – with more equipment on site, again, also higher utilization of that equipment. I mean, we’re pumping now 21-plus hours a day. So you’ve really gotten very efficient on site. But at the same time, that should or it stands to reason, and I can’t quantify this for you today, but it stands to reason that should increase attrition. And we’ll see that attrition at the lower end of the market on the less economic equipment, which today is the Tier-2 diesel stuff. So we think that across the industry, we’ll see more of that coming out over the near term.

Okay, Andy. Thank you. That’s very helpful. And then the other question I had was, back in the NexTier days, I know Matt and the team are working hard on kind of the integration of services at the wellsite and adding kind of incremental profitability there. Where does that stand right now kind of across the company-wide fleet?

Yes. That’s one thing NexTier has done a great job of, with all the different service lines they had. So it wasn’t just hydraulic fracturing. It was logistics, power solutions and moving natural gas, managing sand, contracts, et cetera. As we merge Patterson-UTI next year together, we were missing those pieces on the legacy Patterson-UTI fleet. And there were some quick wins on that coming out of the gate post-acquisition merger of the businesses. And then as we work through the year, we’ve seen more of that. There’s still some more upside on that, but it’s been a steady increase of various of the subsegments moving on to that fleet and further integrating over the last year.

Great. Thank you for the details gentlemen.

Thanks.

Your next question comes from the line of Keith MacKey with RBC Capital Markets. Please go ahead.

Hi, good morning. Maybe just wanted to start out on the free cash flow returns. Certainly, has been a priority for Patterson. You’re going to do the $400 million of returns this year. And I know it’s early to start talking about 2025. But certainly, you have mentioned potentially accelerating free cash flow returns and buybacks on this call a couple of times. So maybe if you could just kind of frame out how we should be thinking about 2025? Is it 50% of free cash flow return? Is it relative to that $400 million number? And really just at this point, what is on and what is off the table? Is it free cash flow returns will come from free cash flow? Or could you potentially use debt to fund the buyback? Just how should we be thinking about the overall framework for next year? And I know it’s early.

Yeah. Hey, Keith, this is Andy. It is early. We are kind of on the front end of our budget cycle going into next year. And so I’m not going to commit certainly to anything more than what we have said is our long-term commitment of 50% of free cash flow to shareholders. I can say that just in general, I don’t foresee us going out and financing some kind of a buyback, doing any kind of a leverage recap through the debt markets. We’re pretty – again, as we said in the call, we’re very comfortable with our investment-grade credit rating. We don’t want to do anything to jeopardize that and a leverage recap would necessarily be kind of exactly the opposite of what you’d probably want to do, if that’s your goal. So I don’t really see that as being something that’s applicable to us, but we’ll give better guidance next quarter around what our actual goals are for 2025 once we’ve gone through our budget process and conferred with our Board.

One of the things we talked about is even though we see a slightly lower overall activity next year, that’s also reduced CapEx. So we’re still going to be producing strong free cash flow next year.

Yeah. Understood. Understood. Andy, just on the integrated job, I know that’s – you’re getting close to finishing up the pad. Can you just talk maybe about some of the early lessons learned operationally and commercially? You’ve been very clear that this isn’t bundling. Just curious to see how the reception of that has been from the customers? Do they see it that way as well?

Yeah. What I’m hearing is that the customer is very pleased with what we’ve done in this whole process. With all new things, there’s certainly some bumps as you get started. But we’ve beat the curve on every well we’ve drilled so far on the pad and things are going really well in the overall process as we move over to completions. And so overall, it’s going really well. I think the most interesting thing about a project like this, and I think as we get into discussion for more, we’ll really understand what that potential is. But we would not have necessarily run all of our services for this customer as we are doing today if we hadn’t presented this opportunity to them to allow us to allow our businesses to work together, integrate some workflows in some places and then try to exceed what their plans were and bring production forward. And so the fact that we’re running more services and selling more products from our businesses than we would have initially, to me, is probably the biggest win. And then, of course, we’re going to get a bonus for outperforming at the same time. But excited about the potential. It’s still early days. We’re in some discussions with some other E&Ps who see what we’re doing on this project. And again, as I said before, if you’re a multinational E&P, this is probably not for you. You’ve probably got plenty of support in your offices where you may not need our help across the entire spectrum. But when you think about some of the mid-tier E&Ps in the U.S. that may not be staffed the same as a multinational, and we offer some opportunities to bring in some extra expertise in different areas to bolster what they are doing and help them out and help bring production forward for them.

Okay. Thanks very much.

Thanks.

Your next question comes from the line of Ati Modak with Goldman Sachs. Please go ahead.

Hi. Good morning team. So, as you talk about the budget for the next year in terms of CapEx, I am just curious about your approach to that. Do you have a target return that you are focused on and then back into the CapEx needs, or are there certain CapEx components that might be relatively more rigid given the focus on gas power fleets?

Yes. Again, we are just starting the budget process. I am not going to get real specific about dollar values. But I will say, in general, we are pretty comfortable with operating in an environment where we are converting about 40% of our EBITDA to free cash flow. And so if you back into that based on whatever, you sort of think about your projections for 2025, you can kind of come to a number. So, that’s really the framework that we are operating under today and that we will continue, likely continue to operate under.

Got it. And then you mentioned in the prepared comments that pumping hours on your electric fleets were pretty good. Any color you can provide on maybe what that number was for the electric fleets or what an average number is across the fleet mix today? How does that compare to last year and expectations for ‘25 as we work through efficiency improvements?

Good question. I don’t have all those numbers in front of me. I will tell you that as we gain more experience with the electric equipment, we have increased the amount of hours that we pumped. So, they are very competitive with what we have done on Tier 4 DGB plus you get the higher substitution rates. So, in general, it’s working well. Everything that we do is pumping 20 hours to 21 hours a day at a minimum. And that’s just really kind of the baseline expectation for all of our fleets that are out there working today. And the electric is certainly in that and moving up a little bit higher at the same time.

Awesome. Thank you.

Your next question comes from the line of Arun Jayaram with JPMorgan. Please go ahead.

Hey Andy, I wanted to start with completions. Looking at the numbers, it does appear that PTEN has lost a bit of share in completions over the past few quarters. I was wondering if you could just comment on your thoughts on just share. How important do you think it is for PTEN to get its share back, and perhaps just your overall strategy during the current RFP season?

Yes. I don’t think we really lost any share. I think that some of it is customer mix and what different customers are doing with their plans. But share is certainly not our primary focus. Our primary focus is cash, it’s dollars, it’s margin. That’s where our focus is. But I think you will see things play out across 2025 that we will be holding our own share. I think in the fourth quarter, you are just seeing some specific customer cases that we have where we have got customers that are, in some cases, wanting to spend less than what they had budgeted. But I think with the reset you will see in ‘25, the increasing activity in the first half of ‘25 will show that we still have roughly the same share.

Got it. And as we think about fourth quarter, a bit of an anomaly here. But as we think about the first half of next year, Andy, help us think about how many incremental fleets you expect to come back into the active fleet count for you? And just general thoughts on pricing conditions perhaps at the premium end of the market.

I think that you have seen this year – I will start with the pricing. You have seen this year where pricing has been under pressure. We are still going through a bit of an RFP season across the industry. Could be a little bit more pressure as we get into ‘25. I think that pricing will really kind of stabilize as we start off 2025 and then that – those events will be behind us. In terms of fleets, I think what you will see from us in overall activity level and active horsepower that it may not get back to where it was at the end of the first quarter. But by the end of the first half, I think we will be back to where we were at a level that kind of reflects Q2, Q3 this year.

Great. That’s helpful. Thanks a lot.

Your next question comes from the line of Waqar Syed with ATB. Please go ahead.

Thank you for taking my question. Andy, do you have plans for additional e-fleet new building next year?

Hey Waqar. So, yes, we do have plans within the CapEx budget to bring in new technology. We have already brought in, for instance, a natural gas reset pump that we are working in the field today. We may expand on that. We may expand on what we are doing with electric. But we will be bringing in high-tech at the higher end of the market that burns 100% natural gas. I think it’s not a one size fits all. It’s not everybody that’s using electric out there. There is other solutions that can burn 100% natural gas. So, I think it’s a bit of a mix. But we will continue to invest at the higher end of the fleet within the overall CapEx budget, which we have said will be a little bit lower next year than this year.

Okay. And then the 155,000 horsepower that you have of e-fleet, are you running all the e-fleets in like e-fleet, they are on their own fleets, or are you taking some of the equipment and putting it into your traditional conventional equipment, so you have mixed type of fleet?

We have a mix of multiple configurations. So, we are running full e-fleets on standard. We have got full e-fleets on simul-frac, and we have also got Tier 4 DGB where we supplement and have maybe a couple of the e-pumps on location at the same time where we do that. And in some cases, we will start a Tier 4 DGB with some electric as we transition a customer from Tier 4 DGB to electric as well. So, sometimes it’s a transition. Sometimes, it’s just that we add a couple of electric pumps to boost the overall displacement of natural gas. So, we do things for a variety of reasons depending on location, basin and customer.

Okay. And what proportion of your fleets are horsepower would you characterize as Tier 4 DGB and e-fleets?

Basically, what we have said is 80% of what we are running today burns natural gas. And there is even – in that mix, there are some Tier 2 dual fuel in that mix, and they are still bringing value to customers, but we don’t intend to continue to invest in Tier 2. But so that means that it’s probably around 70% of what we run is a combination of both Tier 4 DGB and electric or 100% natural gas reset.

Okay. And then just final question on drilling margin bottoming, you have about $15,000 margins guidance for Q4. Is that the bottom or do you see additional declines as we get into next year?

I am not sure we know yet. We haven’t really worked on the full budget for next year. I do think that activity is relatively steady. I do think that it helps us where we continue to do some technical and technology add-ons on some of the rigs that are out there. So, I will defer on that. But I would say, overall, things are relatively steady.

Okay. Great and thank you very much. Best of luck.

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

Hey guys. Thanks for taking my call. You noted some additional synergy opportunities still remaining with the integration of NexTier and Ulterra past what you have done to this point. Wondering if you could give some examples of where you could see additional uplift or what there is left to do there.

Yes. So, I was talking about earlier, especially on the NexTier now on the completion side, we have still got some frac out there that aren’t fully integrated necessarily with our wireline or our logistics. And I think there are some still some more opportunities where we will see that improve. And one of the things that goes underappreciated, it’s part of the completions business, but it’s submitting, and submitting is actually more related to drilling, and that business has been growing. And while it’s small relative to hydraulic fracturing, it’s doing really well. And we think we are now one of the bigger players in submitting in the U.S. as well. So, overall, there are some really good things happening in there despite what we are seeing with some of our customers slowing down in Q4. We are still seeing some good work by the teams and how they are running the businesses, how they are providing very efficient services for the customers. And we think that still bodes well for us in 2025.

Got it. That’s good to hear. It seems like Ulterra is doing reasonably well also, considering the environment. Maybe some additional color on what’s driving the outperformance there and how much of that is in the U.S. versus international?

Yes. And thanks for that. So, as I mentioned earlier, and I use this word specifically, they are doing an excellent job. I mean, if you think about the market we are in, with the rig count in the U.S., the overall U.S. rig count has come down. But yes, at the same time, they continue to produce, continue to show strength in what they are doing across the U.S. And outside the U.S., I think there is still potential to grow. So, I think we have been gaining some share in the U.S. I think we are going to gain share definitely in the international markets just because we have so much more room to go there. And so they are just doing a fantastic job.

Great. Thanks guys.

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

Good morning Andy and Andy.

Good morning Saurabh.

Andy, if you don’t mind, still on the completion side and just to get a flavor of what to expect for the future. If you can just look back, Andy, right? We started the year with close to around $200 million in profitability. We are ending at $85 million. Can you give us some color on how much of that decline is activities/white space, right? So, cost adoption issues versus true pricing, because I am thinking pricing, if it stays flat, at least the calendar utilization white space part of it can come back. And that would give us some clever of what to expect.

No, I think there has certainly been some pricing pressure this year. We have had activity come down. We have had white space in the calendar. We have got a mix of things going on. But there has been some pricing pressure in natural gas basins and even a little bit in the Permian with some of the RFP bids that people have had to go through in processes like that. I do think all that sort of stabilizes as we get going again in the first half of next year. And so even though overall activity might be down a little bit, I do think pricing stabilizes. Q4 is really where we are having the most impact because of the slowdown by some of our customers, but we are going to get into a reset early next year.

Okay. I got it. So, it sounds like pricing is stabilizing, right. So, as utilization starts to normalize, you get your profitability back?

Yes, I think we have seen the majority of the pricing pressure this year and it stabilizes early next year.

Okay. Perfect. I got it. And then Andy Smith, I know CapEx, we will have to wait a little longer to get the details. But as a frame of reference, Andy, can you just remind us the $690 million in CapEx for this year? How do we split that into the various buckets across maintenance, across the market upgrades, across growth? And then for next year, should we bake in some CapEx for the Turnwell joint venture?

Yes. So, maintenance is somewhat tricky when you start thinking about it because, again, as we retire Tier 2 fleets and we replace those with electric fleets, how does that characterize? Is that growth CapEx or maintenance CapEx? So, as you think about it going forward, I don’t think we have anything in our minds that would be necessarily incremental supply to the market. There will be some items that we have traditionally called growth that are high-value return items. I mean these are very good returns, and we spend probably in the neighborhood of $40 million to $60 million on those types of items every year. And then the rest of it is really maintaining kind of our sort of fleet size as well as enhancing the capability of our assets, at the same time just doing the traditional maintenance, which is really kind of the R&M side. So, it’s very difficult to break it into maintenance either this year and/or going forward. So, what I would say is we are looking at a CapEx number next year, just first pass, that is, again, below kind of where we are looking at today, and we will just give better guidance on that as we go forward next quarter.

Okay. No, that’s fair, Andy. And then one very quick one, Andy, and I know somebody asked on the integrated drilling and completion contracts and what’s the feedback from the customers. I will ask the same question, but I will ask you what’s the feedback from Patterson-UTI within the organization, what’s the biggest advantage you see for yourself in execution from a planning, supply chain, technology standpoint, what’s the biggest advantage to you as an organization?

I see a lot of excitement in the people. The people that I talk to on our teams that are overseeing this project and managing the different aspects and coordinating across the different business lines, I see a lot of excitement in the people and that excitement is contagious. And that type of excitement leads to more work. And so that’s exciting. I am going to go with that.

Good to hear. Okay. Andy, thank you for the answers, I will turn it back.

Thanks Saurabh.

Your next question comes from the line of Kurt Hallead with Benchmark Company. Please go ahead.

Hey. Good morning everybody.

Hey Kurt.

Hey. So Andy, maybe just kind of beat the completion horse again here just in the context of maybe the conviction in the recovery in activity that you expect, I know you referenced a number of different times during the call some specifics related to customers that are going to be a drag for you here in the fourth quarter. So, are those – I am assuming, but I just want to be clear that those same customers are telling you yet, we are going to slow down here in the fourth quarter, but you better make sure you got your stuff ready to go because we are going to be kicking it in starting January. Is that the underpinning of the conviction you have on the recovery on frac activity going into next year?

We have very, very strong conviction that these customers are going to restart early in 2025. Our biggest challenge right now is balancing, carrying the cost through Q4 so that we can restart. And so that’s the challenge with what you are seeing in the margins for completions in the fourth quarter. But we want to make sure that we can get off on the right foot when we do restart in the first quarter because service quality is always paramount important along with safety, everything else. So, we are carrying some extra costs in the fourth quarter because we have very strong convictions that they are going to restart.

Got it. Okay. That’s great. And then maybe just a follow-up on the Drilling Products, just maybe an update on what percent of that revenue through the first nine months of the year have been international? And then you got the JV, which should help. But what do you think the – there a lot of conversation about international activity kind of flattening out into next year and especially in Saudi. But given that backdrop, and I think you guys were needing some market share, so can you give us an update on how you think the Drilling Products international business could grow relative to the market?

Yes, I don’t have the exact numbers in front of me. It’s in the range of 30% to 40%, really excited about the international potential for Ulterra just because they are still relatively new in a lot of markets over there. The JV in Abu Dhabi with ADNOC Drilling is – may be a part of that. But I would say it’s not really factoring into the plans. Saudi still has potential for growth. There is other markets. Even though Saudi rig count is coming down, our percent of the share is smaller compared to others, we are moving from a remanufacturing facility to a full manufacturing facility in Saudi. And so we anticipate share growth over there. We are getting more traction in some of the offshore international markets as well where the company has only really started to play over the last couple of years, so excited about the potential.

Yes, Kurt, I would add to that. And again, you know this, but relative to sort of our larger service-oriented businesses, completions and drilling, where if you think about putting an asset into those markets, into those international markets, you really have to be kind of clear on the economics long-term as it’s a pretty big commitment. Ulterra and Drilling Products, they are selling a product and so they can be much more nimble and can really – I mean they are all over the place around the world selling drill bits, and it is a much more – it’s very efficient and it’s, again, it’s a much easier operation to run and to make inroads into the international markets and say the heavy equipment service side would be. So, they continue to sort of expand their international reach, and we will continue to do so, so pretty excited about that.

Got it. Appreciate the color. Thank you.

Thanks.

Your final question comes from the line of Eddie Kim with Barclays. Please go ahead.

Hi. Good morning. Just one question from me. So, you and others have called out and guided to a fairly steep sequential decline in the completions business into 4Q. You mentioned normal seasonal holidays and customers trying to spend within budgets. But is there anything outside of that, that you think could be at play here? Customers holding off on activity because of oil price volatility or waiting to get more clarity on what OPEC is going to do? Just any other factors you are seeing based on your conversations that might be contributing to customers kind of slowing down here in 4Q?

Yes. That’s a good question, and welcome to our calls. So, what we are seeing in completions over the last couple of years has been steady increasing efficiency. And I think that a number of our customers have not completely baked their plans around these increasing levels of efficiency. In a lot of cases, we have finished programs early and customers have elected not to spend early on the next year’s budget yet until they get clarity on what that’s going to look like. I really don’t think it has to do with volatility in commodities. I think that our customers have been more neutral to what’s going on with commodities because they have been trading within a range. And I don’t hear from any customers that they are waiting on any signal from OPEC or any other changes in commodity. I really think it’s really more about planning and looking at their specific budgets. And in our case, we had six customers that didn’t want to overspend or dip into next year’s budget. In some cases, wanted to reduce this year’s budget, but I think as we get into ‘25, we will see the E&Ps working with our own teams to better prepare for what that pace looks like for the year and things could be more normalized next year than they were this year.

Got it. Great. Thanks for that color. I will turn it back.

Thanks.

Thank you. And that is the end of our Q&A session. I would like to turn the conference back to Andy Hendricks for closing remarks.

Thanks Perilla. So, I just want to thank everybody for dialing into the call today. And once again, I would like to thank all of our teams across Patterson-UTI for all the great work that you do for our customers and for our shareholders. Thanks a lot.

Thank you. And this concludes today’s conference call. Thank you all for participating. You may now disconnect.