Thank you for standing by. My name is Danica, and I will be your conference operator today. At this time, I would like to welcome everyone to the Patterson-UTI Second Quarter 2024 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question-and-answer session. If you would like to ask a question during this time, simply press star followed by the number one on your telephone keypad. If you would like to withdraw your question, press star one again. Thank you. I would now like to turn the call over to Mike Sabella, Vice President, Investor Relations. Please go ahead. Thank you, operator. Good morning, and welcome to Patterson-UTI's Earnings Conference Call to discuss our second 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, patenergy.com, and in the company's press release issued prior to this conference call. I will now turn the call over to Andy Hendricks, Patterson-UTI's Chief Executive Officer. Thank you, Mike. Welcome to our second quarter earnings conference call. We are pleased with the way we've been managing our business through the current macro environment. We are focused on deploying a capital-efficient operating strategy that looks to maximize our returns through the cycle. Free cash flow was strong in the first half, demonstrating the resiliency of our business. We are continuing to prove out the free cash flow potential of the company in all macro environments. Since September 30th, 2023, or just after the close of the NexTier and Ulterra transactions, through June 30th this year, we've used our free cash flow to repurchase 28 million shares for $309 million, pay a steady dividend, and lower our net debt, including leases. The free cash flow generation capability was a key reason we combined these businesses, and it is proving effective. We will continue to direct our capital to high return investments and use our capital allocation strategy to maximize the value for shareholders. It's increasingly clear that there will be winners and losers in the oil field over the next several years. Our customers recognize that service pricing is just one aspect to maximizing their returns, and partnering with the right service provider who can provide both technology and an integrated suite of services is crucial. By delivering a superior and differentiated service offering to our customers, we are confident that we can deliver differentiated returns and growth for our investors. Even outside of industry activity, we see a path for capital-efficient growth for Patterson-UTI over the next several years. As one of U.S. Shale's largest drilling and completions companies, we have a unique position in the market. We aim to leverage our position to drive growth for our shareholders. We have recently entered our first fully integrated drilling and completion arrangement with a performance-based contract, where the customer will use our core products and services across an entire pad. We are excited by the initial feedback and believe there are good growth opportunities for an integrated drilling and completion offering. By leveraging our position to create value for our customers, we see a unique opportunity to create differentiated capital-efficient growth for our shareholders. This approach could offer a path to improve long-term returns that would be difficult to replicate. Our integrated drilling and completion offering is enabled by our digital operating systems, allowing both our team and the customers to seamlessly monitor field assets in order to maximize efficiency and reduce operating costs. We believe we have created a unique leader in the oil field, with customers seeing better results as they utilize more of our services. This sets us apart from nearly every other competitor in U.S. Shale. In addition to the strategy in our traditional drilling and completion markets, we are increasingly excited about the potential we have in our power services. There has been a lot of discussion this year around the increasing demand for power in both the oil and gas industry, as well as in other industries. Our E&P customers are continuing to electrify their growing production facilities, and local utilities are not in a position to supply all the power demand. Outside of E&Ps, we all hear the discussions around new data centers. An individual server component in a data center built today requires 3x the energy consumption of a previous network data server. An AI search takes 10 x the amount of energy as a standard internet search. The demand for power outside of utilities is real. Patterson-UTI has an established technology position in power, dating back to our 2018 acquisition of an electrical engineering and manufacturing business, which specializes in medium and high voltage electrical controls, electrical engineering, controls automation, microgrids, and where we have developed a proprietary battery energy storage solution. At Patterson-UTI, we have primarily used the resources from this business to enhance our drilling rig technology offering. However, this team has also supplied microgrid components and systems to marine vessels, dredge vessels, cranes, and production facilities. On a recent project, the team supplied microgrid components to a company that builds and operates data centers, and we are in discussions for further possible deliveries. Over the last several years through next year, we have built out our capabilities to provide and deliver large volumes of natural gas and manage large power generation facilities in the field. Our integrated natural gas fueling business has reached critical mass in providing CNG and field gas for roughly 2 million horsepower of natural gas-powered equipment. Launched organically by next year in 2021, this business has grown significantly over the past several years. In June, we delivered our 100 millionth diesel gallon equivalent of natural gas for over 13 billion cu ft supplied to our customers. We expect volumes in 2024 to be up more than 25% from 2023. To put our natural gas delivery capacity in perspective, annually, our capacity could generate more than 1 GW h of electricity. The majority of our natural gas-powered fleets operate with our own natural gas fueling systems, and we are also the preferred CNG provider for multiple third-party frac fleets. Our success stems from our frac plus fuels integration, which we believe leads the industry in diesel displacement on dual fuel fleets. Our data shows over 40% more diesel displacement compared to competitors, maximizing fuel cost savings and enhancing the marketability of our natural gas-powered assets. This reliability is more crucial for electric fleets, where there is no diesel fallback option. We've also expanded our platform beyond the frac space with several years of history servicing production and midstream-related customers, and see this as upside potential in the future. We are currently introducing new technology that we believe will further extend our lead in blending CNG with field gas. This innovation helps customers overcome the many challenges in using their field gas to minimize their overall fuel costs more consistently. Our blending technology optimizes natural gas usage in various scenarios, with the greatest potential in oil basins, including the Permian Basin, where field gas treatment is most complex. At Patterson-UTI, our power businesses extend beyond our substantial natural gas fueling operations. Our natural gas supply and delivery business and our electrical engineering and controls automation business complement each other as we deliver a broad suite of power services and assets. There is significant demand for these services both inside and outside of the oil field, and we are exploring further opportunities to provide power services for one of our E&P customer's production facilities and to a large data center. Integration and power are just two areas where we see capital-efficient growth beyond the U.S. rig count recovery. Our Drilling Products segment is in the early stages of realizing the international growth we anticipated when we acquired Ulterra. With strong opportunities still ahead in the Middle East and offshore markets, Ulterra has generated revenue in the deepwater markets in the North Sea, Guyana, and the Gulf of Mexico. We believe this is just the beginning of tapping into this potentially large market. We will continue to use our capital allocation strategy to enhance our returns over time. We are three-quarters of the way to our commitment to return at least $400 million to shareholders in 2024, and are evaluating the best use for the remainder of the free cash flow we expect to generate this year. We will focus on the highest return investments. This should amplify the impact from expected operational growth. On the macro front, activity in natural gas basins steadied early in the third quarter, and natural gas prices have improved slightly since the start of the second quarter. We expect a relatively steady outlook for natural gas activity through the rest of 2024. Looking ahead to 2025, there is potential for increased drilling and completion activity in natural gas basins as domestic demand rises and LNG takeaway starts to come online. On the oil side, our activity trended slightly lower with customer-specific turn from natural gas takeaway constraints in West Texas and New Mexico, as well as short-term disruption from recent M&A activity. We believe these slight declines in oil basins have likely run their course and anticipate a relatively steady outlook in oil basins through the rest of the year. Against this backdrop, Patterson-UTI has remained disciplined in our capital deployment. Even as the market seems to be bottoming in the second half, we are generating strong free cash flow. Looking ahead, we anticipate a modest recovery in U.S. Shale activity in 2025, with steady oil markets and growth in natural gas markets from current levels. In our Drilling Services segment, we saw some impact from slowing Shale activity, but our rig count has outperformed the market over a longer period. But Patterson-UTI's rig release is better than the broader market since the start of last year. Our margins continue to outperform compared to previous cycles. In the U.S., we began the third quarter operating 111 rigs and are currently operating 107 rigs. We believe we are nearing the trough for the year, with customer conversations suggesting that activity is likely to remain relatively steady through the rest of the year. By the end of the year, as larger customers prepare for 2025, we could see a modest improvement in our rig count as those customers high-grade equipment. In Completion Services, customers are likely to use completion activity to manage their budgets for the rest of the year. In the second quarter, we saw increased white space compared to the first quarter. While some reduction in customer activity was anticipated, there was more white space than we expected in natural gas basins. In the third quarter, we do expect activity will improve slightly in our Completion Services segment compared to the second quarter, with some elevated white space and frac activity through the rest of the year. In Q2, approximately 10% of our pump hours were from electric equipment, which generated accretive returns compared to our other technologies. We expect the share of electric equipment in our activity to continue to grow. Currently, approximately 80% of our active fleets are capable of being powered by natural gas. We continue to have great success as we roll out our latest round of electric frac equipment. The operating results for equipment that we added to our fleet in the second quarter has been excellent, and customer feedback has been great. Each of the new electric fleets operated at least 500 hours per month of operation, which is a great result and should demonstrate the capabilities of our team and the reliability of our natural gas fueling business that supports these fleets. We are addressing the market needs with next generation frac solutions in a capital efficient manner. We remain extremely flexible with our technologies and will continue to refine our offerings over the next several years to maximize returns and meet customer needs. Results in our Drilling Products segment remain strong, and Ulterra's revenue in the U.S. again outperformed the change in the U.S. rig count, achieving another record quarter in revenue per industry rig. The trend towards longer laterals benefits Ulterra, as each rig drills more footage per year and requires more drill bits. In the second quarter, impacted by the normal spring breakup, but we expect sequential improvement starting in the third quarter. Internationally, we continue to be impressed with our progress, particularly in Saudi Arabia, with international revenues expected to be up mid-teens percent year-over-year. Additionally, the segment is experiencing growth in the offshore market, where we have a small but growing market share. We are very excited about our future prospects. Even if U.S. Shale activity remains relatively stable, we will continue to explore various avenues to grow our returns and free cash flow across our enterprise. Our strategic investments uniquely position us as a business that can help our customers enhance their returns, while also enhancing our own returns. We believe our suite of products and services positions us to lead Shale into its next phase of development over the next several years. I'll now turn it over to Andy Smith, who will review the financial results for the second quarter. Thanks, Andy. Total reported revenue for the quarter was $1.348 billion. We reported a net income attributable to common shareholders of $11 million, or $0.03 per share in the second quarter. This included $11 million in merger and integration expenses. Adjusted EBITDA for the quarter totaled $324 million, which also excludes the previously mentioned merger and integration expenses. Our weighted average share count was 400 million shares during Q2, and we exited the quarter with 394 million shares outstanding. Our free cash flow for the first half of the year was $206 million. During the second quarter, we returned $164 million to shareholders, including an $0.08 per share dividend and $132 million used to repurchase 12 million shares. During the second quarter, we again opportunistically accelerated our share repurchase program, given the dislocation between the share price and our view of the intrinsic value of a share of Patterson-UTI stock. In the three full quarters since we closed the NexTier merger and Ulterra acquisition, we have used $309 million to repurchase 28 million shares. This is in addition to reducing net debt, including leases and paying a steady dividend. In our Drilling Services segment, second quarter revenue was $440 million. Drilling Services adjusted gross profit totaled $179 million during the quarter. In U.S. Contract Drilling, we totaled 10,388 operating days. Average rig revenue per day was $36,430, with an average rig operating cost per day of $20,230. The average adjusted rig gross profit per day was $16,190, a slight increase from the prior quarter. Our revenue per day was slightly stronger than we expected. On June 30th, we had term contracts for drilling rigs in the U.S., providing for approximately $433 million of future day rate drilling revenue. Based on contracts currently in place, we expect an average of 63 rigs operating under term contracts during the third quarter of 2024, and an average of 39 rigs operating under term contracts over the four quarters ending June 30th, 2025. In our other drilling services businesses besides U.S. Contract Drilling, which is mostly international contract drilling and directional drilling, second quarter revenue was $62 million, with an adjusted gross profit of $11 million. For the third quarter, in U.S. Contract Drilling, we expect to average 108 active rigs with adjusted gross profit per operating day of roughly $15,000. The lower margins are a function of contract rollovers and a lower rig count that is impacting fixed cost absorption for our U.S. Contract Drilling business. Aside from U.S. Contract Drilling, we expect other drilling services adjusted gross profit to be down slightly compared to the second quarter. Revenue for the second quarter in our Completion Services segment totaled $805 million, with an adjusted gross profit of $152 million. As expected, we saw increased calendar white space in the second quarter on a small number of dedicated fleets. In addition, several other dedicated fleets saw reduced pumping hours in natural gas basins. Revenue from our West Texas operations was in line with expectations during the quarter. We see an increase in our completion activity in the third quarter, although we do see elevated white space compared to normal operations, as our customers look to spend within their budgets for the year. For the third quarter, we expect Completion Services adjusted gross profit to increase slightly, driven mostly by higher activity in natural gas basins, with oil basins steady. Second quarter Drilling Productss revenue totaled $86 million, which was down 4% sequentially. Adjusted gross profit was $40 million. In the U.S., revenue per industry rig improved compared to the first quarter, as the company continues to see strong market penetration and steady pricing. The segment did see a decline in revenue in Canada due to normal spring breakup, while international revenues were steady compared to the prior quarter. For the third quarter, we expect Drilling Productss results to improve slightly compared to the second quarter. We see another quarter of growth internationally, as well as the return of normal Canadian activity post spring breakup, mostly offsetting a decline in the U.S. rig count. Other revenue totaled $16 million for the quarter, with $6 million in adjusted gross profit. We expect other third quarter revenue and adjusted gross profit to be flat with the second quarter. Reported selling, general, and administrative expenses in the second quarter were $65 million. For Q3, we expect SG&A expenses of $65 million. On a consolidated basis for the second quarter, total depreciation, depletion, amortization, and impairment expense totaled $268 million. For the third quarter, we expect total depreciation, depletion, amortization, and impairment expense of approximately $265 million. During Q2, total CapEx was $131 million, including $58 million in drilling services, $49 million in Completion Services, $14 million in Drilling Productss, and $9 million in other and corporate. CapEx was below budget during the quarter, largely as a portion of the final payment for our new electric frac equipment, as well as some natural gas fueling equipment, slipped into Q3. For the third quarter, we expect total CapEx of roughly $220 million, with the increase attributable to the final payment on our new electric frac equipment, as well as additional equipment for our natural gas fueling business. We're optimistic activity will begin to improve in 2025. Further, we are excited about the long-term prospects for the industry and our company, and we see big opportunities for Patterson-UTI to further improve our competitive position relative to a recovery in the U.S. rig count. We do retain some flexibility in our CapEx budget in the back half of the year. At this time, we expect to spend below our original CapEx budget of $740 million. We closed Q2 with nothing drawn on our $615 million revolving credit facility, as well as $75 million in cash on hand. We do not have any senior note maturities until 2028. We expect to generate another quarter of strong free cash flow in the third quarter and in the second half of the year. We expect approximately 40% of our adjusted EBITDA to convert to free cash flow in 2024. Our board has approved an $0.08 per share dividend for Q3. For 2024, we expect to use at least $400 million to pay dividends and repurchase shares, which represents more than our usual commitment to return 50% of free cash flow to shareholders. I'll now turn it back to Andy Hendricks for closing remarks. Thanks, Andy. While we expect the overall market in the U.S. to remain steady for the remainder of the year, we have a number of initiatives to achieve capital-efficient growth in advance of a potential rig count recovery after this year. We are extremely excited about the potential for our integrated drilling and completion offering, and we think we can use our suite of products and services to add significant value for our customers and deliver accretive returns for our shareholders. Our operational footprint is unique and difficult to replicate, and we look forward to proving our abilities over time. Energy that drives society comes in two primary forms: hydrocarbon chains and electrons, and at Patterson-UTI, we help produce both. With our power services, we believe we have one of the best offerings in the oil field today, including a sizable natural gas fueling business and a strong electrical engineering and controls business. They are very complementary of each other, and we think there's substantial upside, both inside and outside of the oil field. We're excited about the future for power services at Patterson-UTI. And finally, we are committed to maximizing free cash flow while maintaining the highest quality assets. We think the leaders over the next cycle will be the companies that can deliver a unique and differentiated process to the customer, which should help us deliver capital-efficient growth to our investors. We continue to see strong free cash flow over the next several years, and we will direct that capital towards the highest return investment, including our continued commitment to return at least 50% of our free cash flow to investors on an annual basis. I would like to thank all of our employees for their hard work, efforts, and successes to help provide the world with oil and gas for the products that make people's lives better. With that, we'd now like to open the lines for Q&A, so I'll hand it over to Danica. Great. At this time, I'd like to remind everyone, in order to ask a question, press star, then the number one on your telephone keypad. Your first question comes from Jim Rollyson with Raymond James. Please go ahead. Hey, good morning, Andy and Andy. Morning, Jim. Morning, Jim. So Andy, you talked a bit about obviously the power solutions business, your CNG, and kind of the exciting, you know, outlook for that business. And maybe you could just frame up for us kind of magnitude of that business today, and where do you think that could go in the next three-five years between oil and gas and other industrial, you know, uses? ... Yeah, I think, you know, this is a section of our business that's underappreciated, and we wanted to do more to explain it and to highlight it. You know, we have both an electrical engineering and controls business, along with a very large natural gas fueling position. You know, we actually operate two CNG facilities. We compress and create you know, compressed natural gas, CNG. We deliver it, we have well over 100 truck trailer systems to deliver that out in the field. And so, you know, we have a very large position in this space. You know, to put it into context, it's hard to describe exactly how much it is, but we're powering roughly, you know, as I mentioned earlier, 2 million horsepower of natural gas-powered equipment out there in the field today. Some of that's ours, and some of that's with other companies. You know, to convert it into, you know, a different measure of energy, that would be the equivalent of roughly, you know, gigawatt hour per year of electricity in terms of how much natural gas, you know, we're providing on an annualized basis. So, you know, this is a large business that's probably underappreciated. We're excited about the future growth potential. You know, as we continue to expand, for instance, our own electric frac fleets, we'll continue to power more of that with our natural gas fueling systems. And then outside the industry, you know, we're just starting to do some work in areas that, you know, like the data centers, which we think have high future growth. And yet, these data centers, over time, there's been lots of discussion about this, you know, we're likely to relocate in areas that are close to, you know, fuel sources. And so, you know, we think over the next few years, we'll see significant upside in these businesses doing those types of things. Yeah, Jim, just to follow on to that a little bit, to give you a bit more color on how big this business is. So today, this business is north of a $100 million revenue business, so it's not insignificant. Certainly, a pretty sizable business already. Got it. That helps, and it sounds like that could go up multiples if a lot of these things take hold. Then maybe switching gears for a follow-up, Andy, just, you know, you guys have been running dual-fuel frac fleets for a long time, both between, you know, Patterson at Universal and NexTier. Kind of curious, your initial reaction to now running e-fleets, you know, how you find the performance, how you're thinking about the economics. We obviously hear a lot about that from some of your competitors, but since you're kinda just newer to that part of the game, curious your initial reactions there. Yeah, I guess we've been running electric fleets for almost a year now, and, you know, in full force. We've been testing it before that, trying to decide, you know, which path we were gonna go down. But, we're certainly excited about the efficiencies that we're seeing. But, you know, I think the industry will still be relying heavily on, on, you know, Tier 4 dual fuel, you know, for years to come. So I, you know... As I said before, I don't see a wholesale switch out to electric, and that's why we can be measured in our capital deployment on electric, and that's important 'cause, you know, we still wanna be efficient with our capital. But, you know, we are seeing good take up from it. You know, as I mentioned, the fleets that we're operating today, we've had really good service quality success, but that's a testament to, you know, NexTier as a frac company in general and their ability to run high service quality. And so deploying these fleets, you know, fits right in with what they do. And we'll continue to grow this over time. We're just really excited about, you know, the level of efficiencies that we're seeing right now and the high level of service quality we're delivering with the ones that we've started up. Great. Appreciate the thoughts. Thank you. All right, our next question comes from Arun Jayaram with JP Morgan. Please go ahead. Yeah, Andy, I was wondering if you could maybe elaborate on your integrated drilling and completion offering. Sounds like you have a project that you're working on today. So I was wondering if you could maybe talk about, you know, precisely kinda what you're doing in the field, maybe the potential to expand this, and you don't get hit by, you know, the historical, you know, discounting on the bundling of services. I was wondering if you could walk us through that. Yeah, sure. So, you know, it's one of the things that, that we saw when we were putting the companies together that had potential. And we have a number of E&P customers out there that look at us to provide, you know, services across, you know, the spectrum of what we can do as an enterprise. And so, you know, our ability to combine all that and work with the E&P customers to package it in a way to give us both upside, is what we've been looking at since we put the companies together. And so we're on a project today, and what it's definitely not is, you know, a package of bundled services. What it is intended to do is provide, you know, our services across the spectrum in a way that, you know, we can be more efficient in the drilling, more efficient in the completions, but more than that, try to improve the productivity of the wells. And so that's, that's the intended scope. You know, we do a number of different things. You know, it's, it's the drilling rigs, it's the drill bits for more efficient, drilling. It's the directional and the data analytics that we do on well placement to make sure that we're putting the well in the right place to improve productivity, minimize tortuosity in the wells, so you're not constraining production, and that allows you to have better fracs. That allows-... Have better production, and then the efficiency on the integration of all the services that we do across the completions, between, you know, the frac systems, the wireline, the proppant, the trucking, the logistics, the natural gas fuel systems. You know, and then data connects it all, because we can monitor everything together, and you know, provide a more efficient overall holistic package. And we're doing this, you know, in a performance contract manner, where, you know, we have the potential for upside. So this is not about bundling, but it is about bringing all the services together to provide a more efficient service and, you know, where we can work a deal with an E&P to participate in that upside from all this. Early days, this is our first project. We're excited about how it's off to a good start, but we think things are going well. In the end, you know, it's a way for us to be able to share the value with the E&Ps, you know, as we improve the efficiencies and the production of the wells. Great, thanks. Andy, my follow-up is, I just want to maybe better understand, the white space, you know, call it, headwinds, you know, maybe that, that are persisting a little bit, maybe greater than you, you thought, even though you expect Completion Services to, to grow on a sequential basis. I was wondering if you can maybe separate what you're seeing in natural gas versus oily basins, and is this just a driver of just efficiency gains, or is there more of, something else at play which is driving a little bit more white space? Yeah. So I'll, I'll start by explaining it this way. You know, what we're seeing in terms of white space, in other words, having some gaps in activity, is somewhat our choice. Because, you know, in the second quarter, we did see some more white space in the natural gas basins than we'd planned, and we had said that we're gonna pick up activity in the third quarter, which is we're, we are gonna do. But given the overall softness in the market, there's still some price-competitive basins out there and some price-competitive work that, you know, we've decided we just don't wanna work at that price. And, you know, that, that goes for all of our segments. We think it's important during the, you know, the current softness in the market to protect pricing and protect margin. You know, we see that there's potential for upside in the future on these services as we get into next year, when we have more natural gas takeaway from the Permian, when natural gas is in demand for CNG. And what we don't wanna do is anything to negatively impact the pricing or the margin for ourselves or the overall industry, because we think it's important to try to protect that at this point. So we are gonna see a little more white space, but you know, some of that's because it's our own choice, because there are certain rates that we just don't wanna work our equipment right now. We'd rather you know, protect the sector so that you know, there's more upside for us coming out of this. Makes sense. I'll turn it back. Thanks, Andy. The next question comes from Derek Podhaizer with Barclays. Please go ahead. Hey, good morning. I wanted to go back to the power services conversation. Obviously, this distributed power generation market is starting to gain some steam here, just given everything you went over with utility not being able to service the demand that we're seeing out there. It sounds like you talked about being able to fuel these power sources with your CNG delivery. You talked about the battery energy storage solution that you have. But will you expect to own the actual megawatts? Do you plan on investing in turbines or natural gas reciprocating engines to power these non-oil and gas applications? Maybe just some more thoughts around owning the megawatt over time. Yeah. So potentially. So, we are operating, you know, several natural gas turbines in the field to produce electricity. We're also, you know, contracting some gas recip engines to produce electricity in the field today. And so, you know, we manage those agreements, you know, under the natural gas fueling services that we have under NexTier right now. So we're producing, you know, a lot of megawatts in the field today in terms of electricity to drive our own frac systems. And so we do have experience in doing that. And I anticipate that to grow over time. We are gonna be efficient with our capital in the way we do that, but I do anticipate that to grow. I'll tell you that in general, we're seeing more reliability and more predictability in maintenance and maintenance costs from the turbine systems, and so we think that, you know, over the long term, that's probably gonna be the best answer. And so, you know, we're excited about the potential there to keep things going in that direction. We see it all as an op- Got it. It's still early days in, you know, how we're gonna supply different things outside of the industry. I'll tell you, within the industry, within the E&P production facilities, yes, we have the potential to provide, not just the natural gas blending in the field, potential to provide CNG as backup where it's required for production facilities. Potentially, we could be generating the, you know, the kilowatts and megawatts for those production facilities. Outside of the industry, I think it's early days to know who will do what, and I think you'll see different answers for different types of companies outside the industry based on, you know, where they are. But the good news is for us, you know, we can provide either a holistic solution, or we can provide various bits and pieces, whether it's, you know, a gas treatment facility, or a microgrid, or battery backup system, or we can pull it all together into a package. So I think it's still early days in that, but based on the discussions we're having, there's gonna be upside over the next few years. ... Got it. That's exciting. Appreciate all the color there. Frac capacity tightness. A few of your peers over the last couple of weeks have talked about potentially seeing some tightness in the market in 2025 that can surprise your customers and investors alike. Any comments around seeing accelerated attrition from, you know, Tier 2 diesel or other diesel applications out there? Are you starting to retire some of your legacy pumps? Just some overall thoughts, and if we do get this modest uptick in activity, how quickly can this excess capacity in the frac market be absorbed, and then we move actually into a tighter frac market? Yeah. So let me, let me answer a couple different areas of that. So I'll start with the Tier 2. We do own some Tier 2. We still operate it, a little bit of Tier 2 in the field. We are certainly not investing in Tier 2. So So as Tier 2 hours out, it goes away, you know, and it gets parked, and it will get cut up over time. I think also with the softness in the market, you're seeing some Tier 2 get parked on the side from other companies in the industry, and I don't think that equipment comes back to work easily because it'll need a significant investment. The other thing is, as the market starts to increase next year and demand starts to go up, which we do anticipate for several reasons, both with, you know, the improvements of natural gas takeaway in the Permian, allowing for more oil production and LNG demand for natural gas, and later in 2025. As we see the demand for activity start to pick up, this demand is gonna be on equipment that can burn natural gas. Tier 2 is not gonna have an easy place in there. We're-- You know, 80% of the equipment that we're operating today burns natural gas. We're essentially sold out on everything that can burn natural gas. So as we get into that part of the cycle where we start to see that demand increase, there is a shortage. Not that there will be a shortage, there is a shortage today of that type of equipment. And so, you know, that's going to drive the need for more equipment, you know, high spec in terms of burning natural gas in different forms, whether it's tier four dual fuel, or more electric, or turbine direct drive. And so that's gonna drive that demand. It's also gonna drive pricing and margins in, in completions. Got it. Very helpful. Thanks, Andy. We'll turn it back. All right, our next question comes from Scott Gruber with Citigroup. Please go ahead. Please, go ahead. Yes, good morning. Hey, Scott. Morning. I want to come back to the, the integrated contract. It's pretty interesting. If I think about it simplistically, you know, is it the performance bonus? Is that really the route to making the, the one plus one something more than two? And if that's correct, can you provide some more color on the bonus structure? Like, is it based on the, the full cycle time of the well? How should we be thinking about it? Yeah, it's first off, it's more than one well, it's an entire pad. I don't want to get into the numbers of, you know, what that looks like on this, on this particular arrangement. But, you know, we're out there at what you would consider market rates with the potential upside, you know, for bringing production forward, for improving production on wells, you know, those kind of things that will positively impact our ability to do these types of jobs over time. And so, you know, there is a big efficiency component that we're gonna be able to share with the E&P in this particular case. So, you know, we're excited about this model. As I said, it's early days. We've been working on it since we put the companies together. You know, there are very large E&Ps out there that do this very well. There are mid-sized E&Ps that look for more help in this area. And so there's a broad basket of customers out there that, you know, wanna be able to talk to us about this type of arrangement and what we can do for them to help pull production forward and potentially improve production on a per well basis. That's interesting. And then turning back to just the drilling business. You guys are forecasting about $15,000 a day in margin in 3Q. Are you assuming costs still around $20, just given the little rig count? And how do we think about, you know, where that margin finds its bottom, you know, at current spot rates, if we then add, you know, the kind of average bonus contribution on top, where should we think about margins finding the bottom here? So our top tier rigs are still at about 85% utilization. And so, you know, we've seen the slowdown on our rig count on rigs that are more what you classify as non-Tier 1 Super- Spec. You know, I think the bottom, it's hard to just—hard to call that today. Could be later this year because we, you know, do see the potential for some improvement in 2025. You know, I think this is—you know, we're in kind of a trough situation, but it's gonna be a little bit of a drawn-out trough as we get into next year. Could the rig count tick up for us later this year? It's possible, but, you know, we still think of it as more steady. The rig count for us, we think is relatively steady, because while we may put up a couple rigs for some customers later this year, there could be some challenges in the Permian as we work through this gas storage. But pricing is also holding relatively stable as well. You know, we with the lower rig count, there's, you know, fixed cost coverage. But again, you know, as I mentioned earlier on completions, we're still being selective about, you know, what we're willing to go out and work equipment for. And on the drilling rigs as well, we could probably work a couple more rigs today, but we think it's important to protect the pricing, protect our brand in the market, and not allow pricing to fall below- ... Gotcha. I appreciate the call. Thank you. Your next question comes from Luke Lemoine with Piper Sandler. Please go ahead. Hey, good morning. Andy, you talked about how your e-fleets are performing, and I believe your total fleet, you said, has around 80% of horsepower that's capable of burning natural gas right now. Can you talk about the plans and outlook for more e-fleets next year to maybe scoot the fleet-wide natural gas percentage even higher? I think right now all I want to say is that, yes, we do intend to grow the amount of electric that we have, but not just electric, but other technologies that can burn 100% natural gas. There is demand for that out there. We're gonna do it at a measured pace because, you know, we do wanna make sure that we're, you know, have sufficient capital return to shareholders to allow shareholders to have a good return as well. But we do see that we will grow this over time. I think, you know, maybe on the next earnings call, we'll give you more color on what that looks like, but we do plan to grow the new technology aspect of our completions business. Okay. And then on your 3Q pumping outlook, it sounded like the uptick was primarily related to natural gas activity. Is that correct, or are there any other drivers here as well? I think it's kind of more general across the board, maybe a little bit on the natural gas side. But you remember what we were saying in Q2 is we had some unusual circumstances with a couple of our E&Ps, where the completions were just bumping against the drilling rig, and, you know, we worked through that. And so we did expect activity to come up in Q3. But, you know, we're still in a little bit of a challenging part of the softer part of the market right now, and there's just certain pricing that we're just not gonna go fill the gap and do it for a low price. Okay. Got it. Thanks a bunch. Your next question comes from Stephen Gengaro with Stifel. Please go ahead. Thanks. Good morning, everybody. Good morning. two for me, and you talked about pricing. Are you seeing price competition from older diesel assets? Like, how are customers thinking about price, and how are the conversations around price as you head into the second half of this year? I'd say in general, you know, across our services, you know, pricing and pressure pumping is stabilizing at this point, but at the spot market, you've got Tier 2 equipment out there. So we're certainly not gonna go out, you know, with higher-tier equipment and compete with Tier 2 and try to compete at those pricing levels. But I think you're also gonna see Tier 2 equipment get consumed, because at the pricing level, that Tier 2's working at the spot rate, you can't reinvest. You know, I would say it's probably close to breakeven, and you can't produce enough cash returns, and so over time, that equipment just gets consumed. So I think, you know, we're gonna see attrition in that part of the market, but we're just not gonna go out there and compete with that at the lower pricing. But when we think about completions in general, I think our pricing for what we do and for majority of customers we work for is relatively stable at this point. Okay. Thank you. And then the other one is another follow-up on the integrated drilling completion contracts. I think you mentioned we should think about it as market pricing with upside. And I'm just kind of curious, as we think about this going forward, if it becomes a bigger part of the revenue stream, how should we think about the impact these contracts could have on margins? And are you-- are you at all putting sort of baseline margin at risk? I guess that's what I'm trying to understand. I know you don't want to talk a lot about the minutiae of the contracts, but how do we think about it from a high level on the margin impact, if this becomes a bigger piece of the portfolio? Well, I think it's gonna help activity and margin in a couple ways. First, you know, when we look at what we're doing in these types of arrangements and the discussions we're having, we're bringing in services that maybe we wouldn't have had on the pad in the first place. And so, you know, we're certainly not gonna be going out and saying, "Hey, we're giving a discount to bundle." That's not the intent here, because there's benefits to the E&P. We wanna be able to share in those benefits at the same time. But what we are seeing is that, you know, we're... Even in this particular arrangement that we're in today and the performance contract, you know, there are services that we're gonna provide now that maybe we wouldn't have provided if we had not explained all the benefits of bringing everything together, you know, the efficiencies that we can add in the processes and the potential to bring production forward. Okay, great. I appreciate the call. Thank you. Your next question comes from Jeff LeBlanc at TPH. Please go ahead. Good morning, Andy and team, and thank you for taking my question. Good morning. I think you somewhat alluded to this previously, given that you are taking work off the sidelines, given pricing. But as we look forward to 2025, how should we think about the glide path moving forward, particularly given the fact that the utilization headwinds juxtaposed with natural gas curve and backwardation? Do you see a glide path towards $200 million of gross profit in the first half of 2025? I think that's hard to answer at this point, but I do think that, you know, we, we do see catalysts in 2025 that are positive for the whole sector. You know, by early 2025, the natural gas takeaway should help debottleneck the Permian and allow our E&P producers there that to, you know, move the natural gas out, not have to worry about, you know, the constraints on their production, and then, you know, potentially, either keep activity at least steady, but if not, increase a little bit, too. Then, you know, we all know that there's gonna be some demand from LNG. I think some of that we'll have to wait and see how it's balanced between, you know, the competing efforts of natural gas that flows into the Henry Hub versus, you know, the new gas that's gonna be coming out of the Permian as well. But I do think we will see, you know, increasing demand in the natural gas basin. And so all-- you know, we see all that happening in 2025. Timing and magnitude, I think is a little bit tough to predict from where we are today, but we certainly see some upside next year. Okay. Thank you very much, and I'll turn it back to the provider. Thanks. All right. Your next question comes from Keith Mackey with RBC Capital Markets. Please go ahead. Hi, good morning. Morning. Good morning. Just first wanted to follow up on your comment in the press release about, you know, the effects of natural gas, and particularly E&P consolidation being mostly reflected in current activity levels. Can you just give us some more color in terms of, why, why you think that is, as we stand today? Yeah, I think that it... You know, what we said early on in the year when we took a lot of questions about, you know, what does all the consolidation mean for the sector? In general, you know, when you have the E&Ps come together like this, you know, you have a little bit of a pause in activity as the operational, you know, arms of these companies, you know, pull themselves together and decide what operations looks like going forward. And so, you know, we're seeing that work its way through the system across the industry right now, as, you know, these E&Ps work on their various mergers and make these kind of operational decisions. And so we're seeing this pause, you know, just kind of work itself through. And so, I think we're in that right now. I don't think it gets any worse than it is from an activity standpoint because of that, and so there's some upside as this kind of works its way through in the next year. Got it. Okay. And just, just my second question here is, I noticed, you know, in the press release, you've changed the language from, "You expect to convert at least 40% of EBITDA to free cash flow this year," to, "Approximately 40% of free cash flow this year." Am I just reading too much into the language, or is there something on the CapEx or working capital we should be thinking about that, that brings that number closer to 40 instead of above 40? I don't know that our change in language was intentional. But what I will just say is, as you've heard us talk about in the past, we do have some lumpiness to our working capital, especially around some customers that choose to do some things around year-end planning for themselves, prepayments and things like that. It can affect working capital, you know, relatively significantly, but there was no intention to change that language, or give you any sort of concern around that. Got it. Okay. Thanks. That's it for me. Thanks. Your next question comes from Saurabh Pant, Bank of America. Hi, good morning, Andy and Andy. Maybe I'll start with something, something unrelated. So you issued a press release in May talking about signing a non-binding term sheet with ADNOC Drilling, and that's obviously a potentially very big opportunity. I know it's non-binding, it's early, but Andy, can you give, give us some color on that? Just talk about the opportunity and what are the next steps that we should look forward to in terms of realizing that opportunity potentially. Yeah, there's still some things we're working through. You know, as I said before, that we're excited about the opportunity to expand our presence in the Middle East. We're also excited that, you know, we think we have an avenue to do it in a capital-efficient manner. And as you mentioned, we did previously announce that we entered into this non-binding agreement to form a JV with ADNOC Drilling. And this process, it's still ongoing, but I look forward to providing more color when we have something more definitive to report. But it's still in progress. Okay, perfect. We'll look forward to more color, Andy. And maybe a quick follow-up on the CapEx comment, Andy, Andy Smith, that you had, I think, in your prepared remarks, that you expect the CapEx to be below original $740 million number. Can you give us a little more color, Andy? Where's the potential opportunity for reduction versus that number? How should we think about the potential magnitude that you can cut from that level? And then just the base maintenance CapEx, how is that trending? Is it getting more expensive to maintain your assets, or is it more or less what it was? Yeah, I would say, Let me start from the last, and then I go backwards. So I would say on maintenance capital, I wouldn't say that there's necessarily been any significant change, in terms of the increase recently, in terms of maintenance capital per rig or per fleet or anything like that. And on the order of magnitude of what could it be under? And the reason why it's under is, to be fair, we've seen a little less activity, which again, lends itself to a little less maintenance capital. Now, on items that are growth or replacement or fleet additions or things like that, those are kind of long lead time, a little bit more difficult to manage. But around the maintenance capital side, we do have some flexibility and some things that we can, you know, obviously kind of reduce in the back half of the year to bring that number down. So I don't wanna give a specific number around where I think that number's gonna come in, but I do think that $740, you know, we'll be below $740, and that's why we called it out. Okay, perfect. No, I got it. Okay, Andy, thanks for those comments. I'll turn it back. Thanks, guys. Our final question comes from Sean Mitchell with Daniel Energy Partners. Please go ahead. Good morning, guys. Thanks for squeezing me in here. Just a quick one on the field blending technology and the CNG business. It seems like it's got a decent growth profile in its early days. Is there anything on the component side, supply chain-wise, that you could see a bottleneck? Or do you see any bottlenecks potentially there? Well, and one of the things we're doing, you know, we have a path to some, what we think is some interesting IP on this. So we are working to protect, you know, the process and some of the mechanisms of how we do things in the field. There are potential bottlenecks, but we think we've been in front of it in terms of ordering early 'cause there's long lead items to be able to assemble this equipment. But it's not just about the natural gas, but also, you know, in terms of, you know, if we're talking about what's happening in completions and frac, it's not just about the natural gas when you talk about these services, but if you're referring to electric and the volumes of natural gas we use, it's also about, you know, having some control over the power generation and the turbine systems, and we believe we're working to stay ahead of that as well. And so I think I'm excited about, you know, where we're going with this in terms of growing new technology in the field. I think that our teams are doing a really good job of, you know, getting our footprint established with long lead items to make sure that not only are we being able to be in control of the natural gas delivery at the well site, but we can also, you know, have more, a little more control and ownership of the, turbine systems as well. Thanks, Andy. And then maybe one more for me, just kinda last one. Just as you think about next year, you guys are kind of several months in, you know, you're kinda half a year in. Any lessons learned, good or bad, from the transaction you'd be willing to share? You know, you never wanna have to do two transactions at the same time, but we were fortunate to be able to bring in two great companies to Patterson-UTI. You know, these are, these are... You know, one was a really large one, one was a little bit smaller one. The outside help on the integration and keeping everybody on track was a great benefit for us. I believe that, that helped us do things quickly. I can't say enough for our legal teams and our finance teams and all the, you know, late night hours that they were burning to get all this done when they did it. It's a lot of heavy lifting to get through all these things. The operational teams have done a great job pulling everything together. You know, we said on the last conference call, integration is essentially done, and I believe that. Everybody's working and pulling together as one team. You can certainly see it on this new arrangement that we have with the performance contract, you know, where we're gonna run all the services that we have for this customer. And so it's exciting times for us. I do think there's further upside on the NexTier side, because even though the integration's done, we're still working to bring more vertical integration into the suites that we're offering. We're running wireline on about half our fleets right now. I think there's still some upside on that because the efficiencies that we get by running our own wireline on our own Completion Services, and we're running chemicals on about two-thirds of our fleets, there's probably some potential upside from there. Some small things like that that still offer some upside. Mm-hmm ... you know, post-integration, just to add some more verticals within what we're doing. Yeah, Sean, I would echo that, echo that. I would say, you know, look, in any integration, in any acquisition, you know, they're, they're fraught with risk around, you know, the execution of actually bringing the company together. And the three teams really worked very, very well together. There are a million details that we don't talk about because we're all handled, you know, seamlessly. And, you know, again, I've, I've said it in the past, I don't think, you know, from our customer standpoint, anybody, you know, we never missed a beat. You know, it, it is ongoing. It will continue. You know, as you can imagine, bringing these businesses together will just take time, especially around, you know, back office and things like that, as we consolidate further. But it's been really, you know... I can't imagine it could have gone much better, so I'm really very appreciative to everybody internally that worked very hard on that. A couple more points I'll add. The people in the operations are better than we expected in both businesses, so it's been a lot of fun to be able to pull it all together and work with everybody. That's been going great. The other point is, my team's telling me that if you're gonna do a big, you know, merger and integration, take your vacation before, because you won't have time to take it after. Yeah. Thanks for the color, guys. Thanks, Sean. All right, I will now turn the call back over to Andy Hendricks for closing remarks. I wanna thank everybody for dialing in today. Again, I wanna thank all our teams across all of Patterson-UTI for what they do every day, and thanks again. Appreciate it. Thank you, everyone. That concludes today's call. Thank you for joining. You may now disconnect.