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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. [Operator Instructions]. 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 take no obligation to publicly update or revise any forward-looking statements. Statements made in this conference call include non-GAAP financial measures. The required reconciliations 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, President, Patterson-UTI as 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 30, 2023, or just after the close of the next tier and Ulterra transactions through June 30 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 combine 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 oilfield over the next several years. Our customers recognize that service pricing is just one aspect of 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 oilfield 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 of the power demand. Outside of E&Ps, we all hear the discussions around new data centers. An individual server component in the data center built today requires 3 times the energy consumption of a previous network data server. And an AI search takes 10 times 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, micro grids 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 delivery. 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 million diesel gallon equivalent of natural gas or over 13 billion cubic feet 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 gigawatt hour 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 complemented 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 oilfield. And we’re exploring further opportunities to provide power services for one of our E&P customers’ production facilities and to a large data center. Integration in Power 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. And we believe this is just the beginning of tapping into this potentially large market. And we will continue to use our capital allocation strategy to enhance our returns over time. We are three quarters away 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 takeaways starts to come online. On the oil side, our activity trended slightly lower with the customer-specific churn 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. The 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 we’ll continue to refine our offerings over the next several years to maximize returns and meet customer needs. Results in our Drilling Products segment remained 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 benefit Ulterra as each rig drills more footage per year and requires more drill bits. In the second quarter, impacted by the normal spring breakup, 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. 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 [ph]. 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 30, 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 at an average of 39 rigs operating under term contracts over the four quarters ending June 30, 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 products 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 Products 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 screen 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 Products 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 are 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 account 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 oilfield today, including a sizable natural gas fueling business and a strong electrical engineering and controls business. They are very complementary to each other, and we think there’s substantial upside both inside and outside of the oilfield. 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.

[Operator Instructions] Your first question comes from Jim Rollyson with Raymond James. Please go ahead.

Hey good morning Andy and Andy.

Good morning, Jim. So Andy, you talked a bit about, obviously, the Power Solutions business, your CNG and kind of the exciting 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 3 years to 5 years between oil and gas and other industrial uses?

Yes. I think this is a section of our business that’s underappreciated. We wanted to do more to explain it and to highlight it. We have both in electrical engineering and controls business along with a very large natural gas fueling position. We actually operate two CNG facilities. We compress and create compressed natural gas, CNG, we deliver it. We have well over 100 truck trailer systems to deliver that out in the field. And so we have a very large position in this space. To give it -- to put it into context, it’s hard to describe exactly how much it is, but we’re powering roughly, as I mentioned earlier, 2 million-horsepower natural gas-powered equipment out there in the field today. Some of that is ours and some of that’s with other companies. To convert it into a different measure of energy, that would be the equivalent of roughly a gigawatt hour per year of electricity in terms of how much natural gas we’re providing on an annualized basis. So these are -- this is a large business that’s probably underappreciated. We’re excited about the future growth potential. 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, we’re just starting to do some work in areas that -- like the data centers, which we think have high future growth. These data centers over time, there’s been lots of discussion about this. We’re likely to relocate in areas that are close to fuel sources. And so we think over the next few years, we’ll see significant upside in these businesses doing those types of things.

Yes. Jim, just to follow on to that a little bit to give you a bit more kind of color on how big this business is. Today, this business is north of $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. And then maybe switching gears for a follow-up, Andy. Just you guys have been running dual fuel frac fleets for a long time, both between Patterson at Universal and next year. Kind of curious your initial reaction to now running e-fleets, how you find the performance? How you’re thinking about the economics. And we obviously hear a lot about that from some of your competitors, but since you kind of just newer to that part of the game, curious of your initial reactions there.

Yes. I guess we’ve been running electric fleets for almost a year now and in full force, we’ve been testing it before that, trying to decide which path we were going to go down. But we’re certainly excited about the efficiencies that we’re seeing. But I think the industry will still be relying heavily on Tier 4 dual fuel for years to come. So 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 because we still want to be efficient with our capital. But we are seeing good take-up from it. As I mentioned, the fleets that we’re operating today, we’ve had really good service quality success. But that’s a testament to next year as a frac company in general and their ability to run high service quality. And so deploying these fleets fits right in with what they do. But -- and we’ll continue to grow this over time. We’re just really excited about 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 started at.

Great. Appreciate the thoughts, thank you.

Our next question comes from Arun Jayaram with JPMorgan. Please go ahead.

Yes, Andy, I was wondering if you could maybe elaborate on your integrated drilling and completion offering, it sounds like you have a project that you’re working on today. So I was wondering if you could maybe talk about precisely kind of what you’re doing in the field, maybe the potential to expand this. And how as a contractor that 1 plus 1 equals 3, and you don’t get hit by the historical discounting on the bundling of services. Wondering if you could walk us through that.

Yes, sure. So it’s one of the things 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 services across the spectrum of what we can do as an enterprise. And so 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 as a package of bundled services. What it is intended to do is provide our services across the spectrum in a way that we can be more efficient in the drilling, more efficient in the completions, but more than that, trying to improve the productivity of the wells. And so that’s the intended scope. We do a number of different things. 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 you to have better production and then the efficiency on the integration of all the services that we do across the completion between the frac systems, the wireline, the proppant, the trucking, the logistics, the natural gas fuel systems. And then data connects at all because we can monitor everything together and provide a more efficient overall holistic package. And we’re doing this in a performance contract manner where we have the potential of our upside. So this is not about bundling, but it is about bringing all the services together to provide a more efficient service and 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, it’s a way for us to be able to share the value with the E&Ps as we improve the efficiencies and the production of the wells.

Great. Andy, my follow-up is, I just wanted to maybe better understand the white space, call it, headwinds maybe that are persisting a little bit, maybe greater than you thought even though you expect completion services to grow on a sequential basis. I was wondering if you could 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?

Yes. So I’ll start by explaining it this way. What we’re seeing in terms of white space, in other words, having some gaps in activity is somewhat our choice. Because in the second quarter, we did see some more white space in the natural gas basins than we planned. And we had said that we’re going to pick up activity in the third quarter, which we are going to do. But given the overall softness in the market, there’s still some price competitive basins out there and some price competitive work that we’ve decided we just don’t want to work at that price. And that goes for all of our segments. We think it’s important during the current softness in the market to protect pricing and protect margin. 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, where natural gas is in demand for CNG and what we don’t want to 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 going to see a little more white space, but some of that is because it’s our own choice, is there are certain rates that we just don’t want to work our equipment right now. We’d rather protect the sector so that there’s more upside for us coming out of this.

Makes sense. I’ll turn it back. Thanks Andy.

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 the 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.

Yes. So potentially. So we are operating several natural gas turbines in the field to produce electricity. We’re also contracting some gas recip engines to produce electricity in the field today. And so we manage those agreements under the natural gas fueling services that we have under next year right now. So we’re producing 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 going to 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, more predictability in maintenance and maintenance costs from the turbine systems. And so we think that over the long-term, that’s probably going to be the best answer. And so we’re excited about the potential there to keep things going in that direction. We see it as -- it’s still early days in how we’re going to 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 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 where they are. But the good news is for us, we can provide either a holistic solution or we can provide various bits and pieces, whether it’s a gas treatment facility or a microgrid or a 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 going to be upside over the next few years.

That’s exciting. I 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 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 can be absorbed and then we move actually to a tighter frac market.

Yes. So let me answer a couple of different areas of that. So I’ll start with the Tier 2. We do own some Tier 2. We still operate a little bit of Tier 2 in the field. We are certainly not investing in Tier 2. So as Tier 2 hours out, it goes away when it gets parking, 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 will 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 the improvements of natural gas takeaway in the Permian, allowed for more oil production and LNG demand for natural gas later in 2025. As we see the demand for activity start to pick up, this demand is going to be on equipment that can burn natural gas. Tier 2 is not going to have an easy place in there. We’re -- 80% of the equipment that we’re operating today burns natural gas. We’re essentially sold out on everything that convert 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 that’s going to drive the need for more equipment of high spec in terms of burning natural gas in different forms, whether it’s Tier 4 dual fuel or more electric or turbine direct drive and so that’s going to drive that demand. It’s also going to drive pricing and margins in completions.

Got it. Very helpful. Thanks, Andy. I’ll turn it back.

Our next question comes from Scott Gruber with Citigroup. Please go ahead.

Hey [Indiscernible].

Yes, good morning.

I want to come back to the integrated contract. It’s pretty interesting. If I think about it simplistically, is it the performance bonus, is that really the route or making the 1 plus 1 so be more than 2. And if that’s correct, can you provide some more color on the bonus structure? Like is it based upon the full cycle time of the well? How should we be thinking about it?

Yes. 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 what that looks like on this particular arrangement. But we’re out there at what you consider market rates with potential upside for bringing production forward from improving production on wells, those kind of things that will positively impact our ability to do these types of jobs over time. And so there is a big efficiency component that we’re going to be able to share with the E&P in this particular case. So 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. There are very large E&Ps out there that do this very well. They are midsized E&Ps that look for more help in this area. And so there’s a broad basket of customers out there that want to 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 the -- 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 a little rig count? And how do you think about where that margin fund is bottom? Current spot rates have we then had kind of average bonus contribution on top. Where should we think about margins fine in the bottom here?

So our top tier rigs are still at about 85% utilization. And so we’ve seen the slowdown on our rig count on rigs that are more what you classify as non-Tier 1 super spec. I think the bottom hard to call that today could be later this year because we do see the potential for some improvement in 2025. I think this is -- we’re in kind of a trough situation, but it’s going to 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 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 of 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. With the lower rig count, there’s fixed cost coverage. But again, as I mentioned earlier, on completions we’re still being selective about what we’re willing to go out and work equipment for. And on the drilling rigs as well, we could probably work with a couple of 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 a certain level.

Got you. I appreciate the color. 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, this cable burning natural gas right now. Can you talk about the plans and outlook for more fleets next year to maybe skew 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 going to do at a measured pace because we do want to make sure that we’re managing our capital in the right way that we are, 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 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 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 we worked through that. And so we did expect activity to come up in Q3. But we’re still in a little bit of a challenging part of the soft part of the market right now, and there’s just certain pricing that we’re just not going to go fill the gap and do it for a low price.

Okay. Got it. Thanks so much.

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

Thanks, good morning everybody. Two for me. 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?

So I’d say, in general, across our services, pricing for -- pricing and pressure pumping is stabilizing at this point. But at the spot market, you’ve got Tier 2 equipment out there. And so we’re certainly not going to go out with higher tier equipment and compete with Tier 2 and try to compete at those pricing levels. But I think you’re also going to see Tier 2 equipment get consumed because at the pricing level that Tier 2 is working at the spot rate you can’t reinvest. 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 we’re going to see attrition in that part of the market. But we’re just not going to 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 the customers we work for is relatively stable at this point.

Okay. 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 at all putting sort of baseline margin at risk I guess that I’m trying to understand. I know you don’t want to talk a lot about the minutia [ph] 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?

Look, I think it’s going to help activity and margin in a couple of ways. First, 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 we’re certainly not 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 want to be able to share in those benefits at the same time. But what we are seeing is that even in this particular arrangement that we’re in today and the performance contract there are services that we’re going to provide now that maybe we wouldn’t have provided if we had not explained all the everything together, the efficiencies that we can add to the processes and the potential to bring production forward.

Okay. I appreciate the color. 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. I think you somewhat alluded to this previously, given that you are taking work out 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 -- with natural gas curb 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 we do see catalysts in 2025 that are positive for the whole sector. By early 2025, the natural gas takeaway should help debottleneck the Permian and allow our E&P producers there to move the natural gas out, not have to worry about the constraints on their production and then potentially either keep activity at least steady, but if not increase a little bit, too. And we all know that there’s going to be some demand from LNG. I think some of that we’ll have to wait and see how it’s balanced between the competing efforts of natural gas that flows into the Henry Hub versus the new gas that’s going to be coming out of the Permian as well, but I do think we will see increasing demand in the natural gas basis. And so we see all that happening in 2025. Timing of magnitude, I think, is a little bit tough to predict from where we are today, but we certainly see some upside next year.

Thank you very much. I’ll turn it back to the operator.

Thanks.

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

Hi, good morning. Just first wanted to follow up on your comment in the press release about 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 you think that is as we stand today?

Yes. I think that what we said early on in the year when we took a lot of questions about what does all the consolidation mean for the sector. In general, when you have the E&Ps come together like this, you have a little bit of a pause in activity as the operational arms of these companies pull themselves together and decide what operations looks like going forward. And so we’re seeing that work its way through the system across the industry right now as these E&Ps work on their various mergers and make these kind of operational decisions. And so we’re seeing this pause 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 is some upside as this kind of works its way through into next year.

Got it. Okay. And just my second question here is, I noticed in the press release has 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 brings that number closer to 40% instead of above 40%?

I don’t know that our -- 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 relatively significantly. But there was no intention to change that language or give you any sort of concern around that.

Okay. Thanks, that’s it from me.

Thanks.

Your next question comes from Saurabh Pant, Bank of America.

Hi, good morning Andy and Andy, maybe I’ll start with something unrelated -- so you issued a press release in May talking about signing a nonbinding term sheet with no drilling and that’s obviously a potentially very big opportunity. I know it’s non-binding, it’s early, but Andy, can you give us some color on that? Just talk about the opportunity? And what are the next steps or we should look forward to in terms of realizing that opportunity potentially?

Yes. There’s still some things we’re working through. As I said before, we’re excited about the opportunity to expand our presence in the Middle East. We’re also excited that we think we have an avenue to do it in a capital-efficient manner. As you mentioned, we did previously announce that we entered into this non-binding agreement to form a JV with ADNOC drilling in 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. And we look forward to more color, Andy. And maybe a quick follow-up on the CapEx comment Andy Smith that you had I think in your prepared remarks that you expect CapEx to be below original $740 million number. Can you give us a little more color, Andy, was with 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 the assets? Or is it more or less what it was?

Yes. I would say on -- let me start from the last then 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 for fleet or anything like that. And on the order of magnitude of what could be under and the reason why it’s under is, to be fair, we’ve seen a little less activity, which, again, lent 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 obviously kind of reduce in the back half of the year to bring that number down. So I don’t want to give a specific number around where I think that number is going to come in. But I do think that $740 million -- will be below $740 million, and that’s why we called it out.

Okay, perfect. No, I got it. Thank you Andy. Thanks for the comments. I’ll turn it back.

Thanks.

Our final question comes from Sean Mitchell with Daniel Energy Partners. Please go ahead.

Good morning guys. Thanks for squeezing me in here. And just a quick one on the field leading technology and the CNG business. It seems like it’s got a decent growth profile and it’s early days. Are there anything -- 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, we have a path to some -- what we think is some interesting IP on this. So we are working to predict 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 because there’s long lead items to be able to assemble this equipment. But it’s not just about the natural gas, but also in terms of -- 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 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 where we’re going with this in terms of growing new technology in the field. And I think that our teams are doing a really good job of getting our footprint established with long lead items to make sure that not only have we been able to be in control of the natural gas delivery at the well site, but we can also have more -- a little more control and ownership of the turbine systems as well.

And then maybe one more for me, just kind of last one. Just as you think about next year, you guys have kind of several months in you’re kind of happy year in -- any lessons learned good or bad from the transaction you’d be willing to share?

You never want to 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. These are -- 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 helped us do things quickly. I can’t say enough for our legal teams and our finance teams in all the late-night hours that they were perinatal [ph] has 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. We said on the last conference call, integration is essentially done. And I believe that everybody is working and pulling together as one team. You can certainly see it on this new arrangement that we have with the performance contract where we’re going to 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 next year’s side because even though the integration is 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 fleet. There’s probably some potential upside from there. So some small things like that, that still offers us some upside post integration, just to add some more verticals within what we’re doing.

Yes, Sean, I would echo that. I would say, look, in any integration in any acquisition, they’re fraught with risk around 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, but those were all handled seamlessly. And again, I’ve said it in the past, I don’t think from our customer standpoint, anybody -- we never missed a beat. It is ongoing. It will continue. As you can imagine, bringing these businesses together, we’ll just take time, especially around back office and things like that as we consolidate further, but it’s been really -- 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 of more points I’ll add. The people and 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 is telling me that if you’re going to do a big merger and integration, take your vacation before because you will not have time to take it after.

Thanks for the color guys.

Thanks, Sean.

All right. I will now turn the call back over to Andy Hendricks for closing remarks.

I want to thank everybody for dialing in today. Again, I want to thank all our teams across all the patterns on UTI for what they do every day. And thanks again. Appreciate it.