Patterson Uti Energy Inc Q2 FY2024 Earnings Call

Thank you for holding. My name is Danica, and I will be your conference operator today. I would like to welcome everyone to the Patterson-UTI Second Quarter 2024 Earnings Conference Call. Thank you. I will now hand the call over to Mike Sabella, Vice President of Investor Relations. Please proceed.

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 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 NexTier 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 three times the energy consumption of a previous network data server. And an AI search takes ten 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, 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 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 two 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 one 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 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 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 from 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 start 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 to 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 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, 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. 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-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 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.

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 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.

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 the magnitude of that business today? And where do you think that could go in the next 3 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 an 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 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 of 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 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 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 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. 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, Universal, and NexTier. 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, we’ve been operating electric fleets for almost a year now. Prior to that, we were testing to determine the best direction to take. We are definitely excited about the efficiencies we’re experiencing, but I believe the industry will continue to rely on Tier 4 dual fuel for several more years. As I mentioned earlier, I don't anticipate a complete transition to electric, which is why we need to be cautious in our capital investment in electric fleets. It's important for us to manage our capital efficiently. However, we are seeing positive uptake. The fleets we are currently running have shown excellent service quality, reflecting the frac company's overall capacity to maintain high service standards. Deploying these fleets aligns seamlessly with their operations, and we plan to expand this initiative over time. We are genuinely enthusiastic about the efficiencies we're observing and the high level of service quality we've achieved with our initial electric fleets.

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 allow 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 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 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, as 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.

We are currently operating several natural gas turbines in the field to generate electricity, and we are also utilizing some gas reciprocating engines for electricity production. These operations are managed through our natural gas fueling services under NexTier. Currently, we are producing a significant amount of electricity to power our own frac systems, and we have experience in this area, which I expect will expand over time. We plan to be capital efficient in our approach, but I do anticipate growth. Generally, we are observing increased reliability and predictability in maintenance and costs from the turbine systems, which we believe will be the best long-term solution. We are enthusiastic about the potential to continue in this direction. Within the energy and production industry, we see opportunities not only for natural gas blending but also for generating kilowatts and megawatts for production facilities. However, it is still early to determine the specifics of our role outside the industry, as different companies will have varied needs based on their circumstances. The positive aspect for us is our ability to offer both comprehensive solutions and specific components, whether that be gas treatment facilities, microgrids, or battery backup systems, and we can integrate these into a complete package. While it remains early to fully understand the landscape, discussions we are having indicate there will be potential upside in the coming 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 on 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.

Let me address a few different areas. Starting with Tier 2, we do have some Tier 2 equipment and still operate a bit of it in the field, but we are not investing in Tier 2. As Tier 2 equipment becomes less active, it will gradually be taken out of service. Additionally, with the current softness in the market, some Tier 2 equipment from other companies is being parked as well, and I believe it won’t easily return to use since it requires significant investment. Looking ahead, as the market is expected to improve next year and demand rises—due in part to better natural gas takeaway in the Permian, which will support increased oil production and natural gas demand for LNG in 2025—this rising demand will focus on equipment that utilizes natural gas. Tier 2 equipment will not have a strong role in this context. Currently, about 80% of our operational equipment runs on natural gas, and we are essentially sold out of all our natural gas-converting equipment. As demand begins to rise, there is already a shortage of such equipment, which will necessitate more high-spec machinery capable of burning natural gas in various forms, including Tier 4 dual fuel and additional electric or turbine direct drive options. This demand will also impact 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.

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, first of all, it's more than just one well; it's an entire pad. I'm not going to get into the specifics of what that arrangement entails, but we're operating at what would be considered market rates with the potential for increased production through improvements on the wells and similar factors that will enhance our capacity to handle these types of projects over time. There's a significant efficiency aspect that we will be able to share with the exploration and production companies in this specific case. We're enthusiastic about this model. As I've mentioned, it's still early in the process. We've been developing this since we merged the companies. There are large exploration and production companies that excel in this area, as well as mid-sized companies that seek more assistance. Thus, there is a wide range of customers interested in discussing this kind of partnership and how we can help accelerate production and potentially enhance output on a per-well basis.

That's interesting. Turning back to the drilling business, you are forecasting about $15,000 a day in margin in the third quarter. Are you assuming costs are still around 20%, given the current rig count? How do you view where that margin might bottom out? Considering current spot rates and average bonus contributions, where should we expect margins to find their lowest point?

Our top-tier rigs are currently operating at about 85% utilization. We've noticed a slowdown in the rig count for rigs that are classified as non-Tier 1 super spec. It's challenging to determine the bottom of this situation, but it could happen later this year, with some potential for improvement in 2025. We're currently in a trough situation, which may take some time to navigate as we move into next year. There is a possibility that the rig count could increase for us later this year, but we view it as relatively steady. While we might deploy a few more rigs for some customers later this year, we anticipate facing challenges in the Permian as we manage gas storage. However, pricing remains relatively stable. With the lower rig count, we have fixed cost coverage. As I mentioned earlier, we are being selective with completions regarding the equipment we are willing to provide. For drilling rigs, we could work with a couple more rigs today, but we believe it's crucial to protect pricing and our brand in the market to prevent pricing from falling below a certain threshold.

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 it at a measured pace because we do want to make sure that we’re managing our capital in the right way that we 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?

In general, pricing for our services, particularly in pressure pumping, is stabilizing at this time. However, in the spot market, there is Tier 2 equipment available. We will not compete with higher-tier equipment against Tier 2 at those pricing levels. It's also important to note that Tier 2 equipment will be consumed over time because it can't reinvest at the current spot rate pricing, which is close to breakeven and does not generate sufficient cash returns. Consequently, we expect to see attrition in that segment of the market. We won't engage in competition at lower pricing. Overall, when considering our completions, pricing for our services remains relatively stable for the majority of our customers.

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 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?

I believe it will enhance activity and margins in several ways. Firstly, in these arrangements and discussions, we are introducing services that we may not have initially included. Our goal isn’t to offer discounts for bundled services, as we want to ensure that exploration and production also benefit, and we aim to share those benefits. What we're noticing is that in our current arrangement and performance contract, we are providing services that we might not have offered otherwise. This integration allows us to enhance efficiencies in processes and potentially accelerate production.

Okay. I appreciate the color. Thank you.

Your next question comes from Jeff LeBlanc at TPH. Please go ahead.

Good morning, Andy and team. Thank you for taking my question. You mentioned this earlier, especially regarding the work you are taking out of the sidelines due to pricing. As we look ahead to 2025, how should we understand the path forward, particularly in light of the utilization challenges with natural gas pricing and backwardation? Do you foresee a path to achieving $200 million in 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 basins. 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.

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.

Thank you, everyone. That concludes today’s call. Thank you for joining. You may now disconnect.