Patterson-UTI Energy, Inc.

Thank you for standing by. My name is Rebecca, and I will be your conference operator today. At this time, I would like to welcome everyone to the Patterson UTI fourth quarter earnings conference call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star followed by the number one on your telephone keypad. If you would like to withdraw your question, press star one again. Thank you. I would now like to turn the call over to Michael Sabella, Vice President of Investor Relations. Please go ahead.

Thank you, Rebecca. Good morning and welcome to Patterson UTI's earnings conference call to discuss our fourth quarter 2024 results. With me today are Andy Hendricks, President and Chief Executive Officer, and Andy Smith, Chief Financial Officer. As a reminder, statements that are made in this conference call that refer to the company's or management's plans, intentions, targets, beliefs, expectations, or predictions for the future are considered forward-looking statements. These forward-looking statements are subject to risks and uncertainties as disclosed in the company's SEC filings which could cause the company's actual results to differ materially. The company takes no obligation to publicly update or revise any forward-looking statements. Statements made in this conference call include non-GAAP financial measures. The required reconciliation to GAAP financial measures are included on our website at patenergy.com and in the company's press release issued prior to this conference call. I will now turn the call over to Andy Hendricks, Patterson UTI's Chief Executive Officer.

Thank you, Mike, and welcome to our fourth quarter earnings conference call. In 2024, Patterson UTI delivered on our goal to differentiate ourselves amongst the Shale Service Peer Group by using our broad service and product portfolio to deliver value-accretive results for our customers and strong free cash flow for our investors. We balanced the return of capital to shareholders with organic investments that positioned the company to extend our sustainable operating advantage over much of our competition and demonstrated the durable cash conversion profile of our company. As U.S. Shale continues to evolve, we believe service companies that deliver value-accretive solutions to the customer, not just the lowest price, will continue to lead the industry in long-term returns. With our high-quality assets and skilled operating and commercial teams, we are confident in our ability to deliver industry-leading performance. Ultimately, this should allow us to deliver improving returns for our own shareholders in the coming years, even if U.S. onshore activity remains steady at current levels. In the fourth quarter, we delivered relatively steady, adjusted gross profit per day in our U.S. contract drilling business, effectively managed year-end operator slowdowns across the entire U.S. completions market, and we delivered results in the drilling product segment that outperformed industry activity for the year. We concluded 2024 with very strong free cash flow for Patterson UTI. We returned significant capital to our shareholders, which reduced our total share count by more than 6%. We paid a cumulative dividend equal to 4% of our current market cap. In addition, we reduced our net debt, including leases, by almost $100 million. Our long-term strategy to create shareholder value will continue to focus on three key pillars. First, on the commercial side, our goal is to monetize our value-based solutions. We believe our integration strategies within the drilling and completions business can drive significant efficiencies, helping to reduce well costs and elevate returns for our customers, while also benefiting our own returns. As a leader across multiple service and product lines, our offering is difficult to replicate, which should deliver a sustainable competitive advantage. Second, internally, we are focused on managing our own cost structure. Over the past year, both our industry and our company have seen a slowdown in activity. As we prepare for a relatively steady market in the coming year, we are streamlining our costs to better align with current activity levels. And finally, capital allocation. We expect significant free cash flow generation in 2025. We remain committed to return at least 50% of our adjusted free cash flow to shareholders through dividends and share buybacks. Beyond this, we expect to allocate the remainder of the free cash flow into the higher returning projects while protecting our strong capital structure. Our strategy to deliver unique value-based services for our customers is driving deeper integration of our core assets. This approach is paving the way for a commercial model that will allow us to capture more of the performance-driven upside. Last year, we disclosed our first fully integrated drilling and completion arrangement with performance incentives. We recently completed the drilling portion of this program, delivering wells significantly faster than historical averages. This success resulted in performance bonuses for Patterson UTI while also delivering a significantly better outcome for the customer, including bringing production forward. This project only marks the beginning of a strategy that should have good growth potential. Because we touch more of the well side than we have historically, we believe we have reduced the risk of relying on third parties, which should allow us to more closely control our own destiny in operations. Moving forward, our commercial strategy will emphasize more integrated and performance-based agreements, which we believe will drive enhanced margins in the years ahead. During 2025, the macro environment should remain relatively supportive for our business, and we continue to expect steady drilling activity through most of the year. On the oil front, commodity prices are supportive of continued drilling and completion activity in the major US oil basins. Our oil-directed customers are increasingly focused on value drivers, resulting in a high grading of our service providers and equipment. Our position as a high-quality service provider with top-tier assets allows us to outperform. On the natural gas side, we see a positive outlook over the next several years, with a clear need for more natural gas-directed drilling and completion activity to satisfy growing natural gas demand. We could potentially start to see natural gas activity come back late this year and definitely into 2026. Our US contract drilling business continues to deliver strong, adjusted gross margins per day, driven by the efficiencies of our Tier 1 Apex rigs and the quality of the service that we offer. Over the past several years, we have invested to develop a very technical drilling team that integrates automation and performance data analysis into the process and strives for continuous improvement to drill a more efficient shale well for our customers. These people and investments have set our company apart, making it uniquely capable of handling the complexities of the modern shale well, such as extended laterals and faster drilling speed. We are positioned to monetize these investments and unlock the value of our advanced rig technology. We are transitioning more of our drilling services to an integrated commercial and operating model, combining our Tier 1 Apex drilling rigs with directional drilling, down-hole tools like our drill bits and mud motors, well placement data analytics, and ancillary services such as drill pipe rentals and electrical engineering. This approach helps us to capture a greater share of the drilling spend while also enabling our customers to deliver faster, more efficient wells. For Patterson ETI, this will likely result in our company adopting more performance-based agreements. We see potential for margin accretive growth with this approach. In the U.S., we are currently operating 107 rigs, with activity expected to remain relatively steady across both oil and natural gas basins through the rest of the year. Our completion services segment navigated year-end slowdowns with several of our customers by securing work with a few new customers during the quarter while also managing costs. This effort was complemented by expansion of our well site integration services, particularly profit sourcing and logistics. In our CNG power and fueling business, we've successfully launched our new fuel gas technology, delivering excellent results by allowing customers to use more of their trapped fuel gas through our patented technology that improves gas quality and blending. This innovation addresses historical challenges in using fuel gas to fuel frac fleets, such as reduced diesel displacement and increased downtime because of inconsistent fuel gas quality or volume. The industry continues to transition to natural gas powered frac fleets, and our completion scheme has led the way in adopting and deploying new solutions. While electric frac is a great option for some of our customers, tier four dual fuel can be more cost effective for others, as the high capital cost of power generation on electric frac remains a significant hurdle. As each customer evaluates their own needs, our full suite of offerings will fit essentially every situation. As we expand our fleet of Emerald 100% natural gas powered equipment, we've decided to support multiple technologies to retain flexibility and maximize the service offering for our customers. This is the prudent approach when technology options are expanding. And this gives us the ability to offer the best technical solution for 100% natural gas, depending on specific customer applications. In 2024, we worked with our OEM engine supplier to field test direct drive technologies, and we intend to deploy more of this new technology into our Emerald fleet this year. Direct drive systems offer a breakthrough by enabling fleets to run entirely on natural gas without requiring large capital investments for external power generation. These systems are generating strong commercial interests from our customers, and we anticipate these direct drive technologies will gain market share in the coming years. Our flexible approach to technology deployment enables us to adopt quickly to the changing market demands. We operated more than 150,000 horsepower Emerald 100% natural gas powered completion equipment to start the year, and we expect to surpass 200,000 horsepower by mid 2025. Across the industry, we believe all equipment that can be powered by natural gas is effectively sold out, including our dual fuel assets. Roughly 80% of our active fleet can be powered by natural gas. Our drilling product segment concluded a very successful year in 2024 that saw the business outperform industry activity, both in the US and internationally. In the US, revenue was down less than 5% year over year, despite a more than 10% decline in the industry recount, demonstrating the resiliency of a business driven by superior technology and a laser focus on customer service. Revenue improved year over year in our international markets as the company continues to do a great job penetrating new geographies. While our drilling product segment is mostly known for our Altera drill bits, the team has also done a great job developing new products. Our downhill tools and product innovation revenue, which is essentially everything besides the drill bits, more than doubled in 2024 at very strong margins. We have been very pleased with the entrepreneurial spirit of our drilling products business, and we expect to continue to outperform the industry. When speaking with investors and analysts, one of the most frequent topics is the outlook for power, both inside and outside the oil field, and Patterson UTI's role in this evolving market. With power demand expected to grow exponentially over the next decade, the oil field services industry is well positioned to capitalize through rising natural gas demand and our capabilities as a provider of power generation assets. Patterson UTI has a long history in oil field power generation. The drilling industry transitioned to electrification decades before the frac sector, and each of our rigs operates with over 4 megawatts of our own power generation. At peak times, our drilling operations alone have utilized more than a total of 500 megawatts of mobile power. Today, we also operate nearly 150 megawatts of power alongside our electric frac fleets. Mobile power generation is already a core competency of Patterson UTI, and we are prepared to deploy capital to satisfy increasing power demand, but only when opportunities align with return thresholds for our investors. We see significant potential to support our customers as they continue to electrify their compression systems and production pads that cannot be reached by the grid. Combined with our ability to supply natural gas to these systems, our expertise positions us to expand this business profitably as the industry evolves. I'll now turn it over to Andy Smith, who will review the financial results for the fourth quarter.

Thanks, Andy, and good morning. Total reported revenue for the quarter was $1,162 million. We reported a net loss attributable to common shareholders of $52 million, or 13 cents per share, in the fourth quarter. Adjusted EBITDAF order totaled $225 million. Our weighted average share count was 389 million shares during Q4, and we exited the quarter with 387 million shares outstanding. During 2024, we generated $523 million of adjusted free cash for it. During the fourth quarter, we returned $52 million to shareholders, including an 8-cent per share dividend, and $20 million used to repurchase approximately 2.6 million shares. For the full year, we used approximately $290 million to repurchase shares, and we reduced our share count during the year by over 6%. This is in addition to reducing net debt, including leases, by nearly $100 million, and paying a steady dividend. In our drilling services segment, fourth quarter revenue was $408 million, and adjusted gross profit totaled $163 million. In U.S. contract drilling, we totaled 9,617 operating days. Average rig revenue per day was $35,300, with average rig operating costs per day of $19,600. The average adjusted rig gross profit per day was $15,700. On December 31st, we had term contracts for drilling rigs in the U.S., providing for approximately $426 million of future day rate drilling revenue. Based on contracts currently in place, we expect an average of 64 rigs operating under term contracts during the first quarter of 2025, and an average of 40 rigs operating under term contracts over the four quarters ending December 31st, 2025. In our other drilling services businesses, which is mostly international contract drilling and directional drilling, fourth quarter revenue was $69 million, with an adjusted gross profit of $12 million. For the first quarter in U.S. contract drilling, we expect to average 106 active rigs, with adjusted gross profit per operating day of approximately $15,250. Adjusted gross profit per day expectations are expected to start to see some benefit from performance bonuses. We expect other drilling services' adjusted gross profit to be flat compared to the fourth quarter. Revenue for the fourth quarter in our completion services segment totaled $651 million, with an adjusted gross profit of $95 million. As expected, we saw white space as several of our customers slowed completion activity sequentially. However, our team did an outstanding job securing work with multiple new customers and controlling costs. Additionally, the segment benefited from greater well-side integration of our ancillary services, most notably from our profit sourcing and logistics system. During the first quarter, we expect completion activity will seasonally recover from the year-end slowdown as customer budgets reset, and we continue to see traction from our integrated completion services as ancillary revenue improves. This is partially offset by some inefficiencies early in the quarter, as crews restarted following the extended slowdown in the fourth quarter. For the first quarter, we expect completion services' adjusted gross profit to be approximately $100 million. We expect equipment that can be powered by natural gas will remain effectively sold out into the second quarter. Fourth quarter drilling products revenue totaled $87 million, with an adjusted gross profit of $37 million. In the U.S., we again saw revenue outperform the overall recount, a credit to the strong market position driven by what we believe to be superior product performance. The segment adjusted gross profit was impacted by a sequential increase in a non-cast charge associated with the step-up to fair value of our drill bits in accordance with purchase price accounting, which increased $2 million compared to the prior quarter. For the first quarter, we expect drilling products' adjusted gross profit to be flat compared to the fourth quarter. Other revenue totaled $16 million for the quarter, with $7 million in adjusted gross profit. We expect other revenue and adjusted gross profit in the first quarter to be flat with the fourth quarter. Reported selling general and administrative expenses in the fourth quarter were $73 million. For Q1, we expect SG&A expenses of approximately $67 million. On a consolidated basis for the fourth quarter, total depreciation, depletion, amortization, and impairment expense totaled $255 million. For the first quarter, we expect total depreciation, depletion, amortization, and impairment expense of approximately $235 million. During Q4, total capex was $140 million, including $54 million in drilling services, $61 million in completion services, $16 million in drilling products, and $9 million in other incorporated. As 2024 unfolded, we showed that we were nimble in our ability to adjust our spending to reflect the changing environment. Our initial capex budget for 2024 was $740 million, but we reduced our spending and ended the year with total capital expenditures of $678 million or more than $60 million lower than we initially anticipated. We also received $26 million in proceeds from asset sales. This demonstrates our ability to quickly respond to the changing market. While we lowered our capex, we still exited the year with more natural gas powered horse power than we initially planned, and we have one of the highest quality drilling rig and completion fleets in the industry. For 2025, we expect capex of approximately $600 million, with capital spend at each of our segments to be lowered compared to 2024. We will continue to invest in next generation upgrades to our drilling rigs and natural gas powered frac horse power, even with a smaller capex budget relative to last year. We expect to have more than 200,000 horsepower of our emerald line of 100% natural gas powered completion assets by mid-year. We close Q4 with $241 million in cash on hand. We do not have any senior not maturities until 2028. Subsequent to the close of the quarter, we have successfully refinanced our revolving credit facility into a new five-year $500 million unsecured credit facility that expires in January 2030. We expect to generate significant free cash flow again in 2025, and we again expect to return at least half of our adjusted free cash flow to investors through shared buybacks and dividends. Our board has approved an eight-cent per share dividend for the first quarter of 2025, payable on March 17th to holders of record as of March 3rd. I'll now turn it back to Andy Hendricks for closing remarks.

Thanks, Andy. I want to close with a few key takeaways. First, I would like to thank our teams across all of Patterson UTI for their outstanding achievements in 2024. We successfully completed the operational integration of our company with Nextier and Ulterra, and we have turned our attention to streamlining costs and enhancing efficiencies. On the cost side, we are in the process of integrating back office functions, which is a key step to maximizing enterprise-wide value of the merged company. We are also advancing toward a more integrated commercial model at both our drilling and completions businesses, designed to further extract value from our expanded footprint. Technology advancement continues to be a core competency of the company, and we continue to deliver exceptional service quality in both our drilling and completions businesses. In drilling, a number of our APEX Tier 1 rigs have enhanced load capacities to meet the demands of deeper natural gas plays in the Haynesville while improving efficiency for longer laterals in the Permian. We are combining our Tier 1 rigs with our downhole technology such as our impact mud motors and the new Ulterra Maverick drill bits, and we have seen a significant increase in demand for our Cortex automation systems. Together, we think this offering delivers the most cost-effective wells for our customer. In completions, we expanded our emerald line of 100% natural gas-powered frac equipment while working with one of our engine suppliers to field test and commercialize their new natural gas-reciprocating direct drive system. We plan to deploy additional technology in 2025. We are in the early stages of realizing the full benefits of our scale across the entire well construction process. Our world-class P10 Performance Center is nearing completion at our Houston headquarters, where we will centralize data management across all our businesses to drive improved performance for both our customers and for Patterson UTI. Our P10 Advantage commercial model is focused on delivering integrated drilling and completions packages, and based on customer feedback, is likely to become a bigger part of our business. Our ability to deliver this full suite of services and products sets us apart in the industry, reducing reliance on third parties and enhancing operational efficiency. Given the strong feedback we've received so far, we think there is a significant upside for our shareholders through a performance-based commercial model, while also benefiting our customers. On the topic of power, our expertise in power generation has been demonstrated over decades, beginning with the electrification of our drilling rigs. We have leveraged our technical capabilities to generate power from a variety of sources, including diesel, natural gas-reciprocating generators, and gas turbine generators. Today, our power assets generate over half a gigawatt per day of electricity, and we supply enough CNG and fuel gas to support around one gigawatt of constant power generation. Power is already a core competency of our company. From our perspective, electrical power as a service can be divided into three distinct markets, where grid power is not currently positioned to meet demand. You have power for frac operations, you have power for E&P production and midstream facilities as a subset of industrial, and power for the largest potential future consumers, hyperscalar data centers. Each of these end markets presents unique opportunities and specific technology requirements. For example, in electric frac, our current preferred option is a high-capacity turbine. Currently, the power for our frac fleets is financed through operating leases, but we recognize that in the future we may choose to deploy capital to own these assets. Given the fast-paced evolution of the market, we have chosen to be measured with our capital before committing to a particular solution. This proven investing strategy is proven effective in our emerald investments within our frac business, and we are focused on ensuring that we make the right investments to optimize the long-term capital efficiency of our fleet. The site power requirements for our E&P customers are significantly less as they develop production pads and midstream compression facilities. Through discussions with suppliers, we have found that the capital cost per megawatt for these smaller units is roughly half the cost of the larger units used to power our frac fleets. Data centers require another level of power consumption, requiring half a gigawatt or more capacity, depending on the size of the project. The capital cost here appears to range from $600,000 to $1 million per megawatt. Data center power demand will continue to grow, despite recent news on AI, with new data centers required for the private sector, government, and military applications. The power demand for new data centers has now tripled out of the older facilities, with additional increases driven by the growing need for AI infrastructure. So where is our focus at Patterson UTI? Based on discussions with our suppliers, we know that large gas turbine manufacturers are already in direct discussions with the data center companies. While there is keen interest in how companies like ours could provide power to data centers, we believe that given the competitive landscape and the enormous capital requirements to meet the power demand for this market, the data center in-market does not appear to be a likely high-return path for Patterson UTI. We are instead focusing our efforts on the areas where we can most effectively leverage our strengths and deliver value to our customers. Within oil and gas, we have the right relationships, geographic support, and experience to offer an integrated power solution for our own E&P customers. We currently have more than 15 megawatts of idle natural gas power generation capacity that we can repurpose. This gives us the opportunity to assess potential returns before deciding whether this is a market where we want to deploy significant incremental capital. What we do not want to create is a commoditized generator rental business that competes with the existing rental companies. Our value proposition lies in combining power generation with other products and services that we have in our portfolio, such as our real-time monitoring, our microgrid engineering and manufacturing, our battery backup systems that are rated for well-side environments, and CNG delivery and fuel-gas blending. By integrating these offerings, we can deliver an integrated power solution that is hard to replicate, leveraging our broader Patterson UTI capabilities. From what we see right now, if we choose to deploy capital in this space, we are more likely to do so through organic investment rather than acquisition. We have seen several potential acquisitions in the oil-filled power generation sector, but we have found the ask price is to be too high. Some of the valuations we have seen are multiples of the capital costs of purchasing new generators, and the acquired assets have significant hours already on them. While these acquisitions might be accretive to current EBITDA multiples, the replacement and maintenance costs associated with these assets could limit their accretive potential on a -on-capital basis, which is our primary valuation metric. We recognize the potential market growth for off-grid utility power solutions within the oil and gas space, particularly in the Permian, and we are actively exploring opportunities in this market. One third-party source estimates that the demand for off-grid power in remote areas of the Permian will grow by more than 4 gigawatts over the next 10 years, driven by midstream and production system needs. We intend to stay disciplined in our capital approach to this market, aiming to generate strong returns for our investors. We do not believe that deploying capital just to buy and rent commoditized generators with low cash flow margins is in the interest of our shareholders. However, we are well positioned to offer integrated power solutions to our customers, and we will continue to explore these opportunities. Over the past couple of years, we acknowledge that we have seen a steady decline in demand for oilfield services in the U.S. as evidenced by the declining rig count. A portion of this can be attributed to increasing efficiencies, with additional impact from the mergers of various EMPs, which has resulted in lower activity at the newly combined entity compared to the pre-merger operations. However, we are seeing evidence that these mergers, while they are a headwind for overall industry activity, could be a relative tailwind for the high-end service providers such as Patterson ETI. Our well-side integration across our drilling and completions businesses is driving value for both our customers and our shareholders. We are increasing product sales into international markets, and we are actively seeking to balance our company's size for the anticipated activity this year in the U.S. This offers upside for our investors, and even in a steady oilfield services market in the U.S., Patterson ETI is positioned favorably to create significant value for our shareholders and drive improving EPS over multiple years. Looking past 2025, there is a discussion about the need for more natural gas production in the U.S. to supply LNG takeaway at the Gulf Coast, for gas exports to Mexico, and also for further baseload electricity demand in the U.S., including for data centers. One major midstream company estimates natural gas production will need to grow by 28 BCF per day between now and 2030. We are bullish on the long-term prospects for natural gas and what that means for more potential activity in natural gas basins and for Patterson ETI. I am upbeat about our company's position in 2025 and beyond, and we expect to continue to generate significant free cash flow, and we will continue to return at least 50% of our adjusted free cash flow to our investors through buybacks and dividends. With that, we'd like to thank all of our employees for their hard work, efforts, and successes, both in our industry and in general in 2024, and we look forward to a strong 2025. Rebecca, we'd now like to open the lines for the Q&A.

At this time, I would like to remind everyone, in order to ask a question, press star, then the number one on your telephone keypad. We'll pause for a moment to compile the Q&A roster. Your first question comes from the line of Jim Rolison with Raymond James. Please go ahead.

Hey, good morning, everyone. Good morning, Jim. Andy, if we circle back on the performance-based contracts, you first kind of started talking about this early last year, if I recall correctly, and now you've had a bit of time to kind of work through some of those early contracts and the evolution of that, and it sounds like it's gaining traction from your comments earlier. Maybe if you could just provide a little bit of color kind of on the financial benefits. You know, we obviously look at the way you report things in terms of rig margins and margins in the completion service businesses, et cetera. But as you think about this over the next two, three years or beyond, maybe just talk about the financial benefits. Does this end up driving more activity? But just kind of put numbers to the concept here, if that makes sense.

Yeah, sure. So let me just start by saying, you know, we've participated in various types of performance contracts for individual service lines for years. Some of that based on, you know, increasing efficiencies, production forward. And we've even had some contracts at times that are tied to commodity prices. And so we've participated in these various risk award scenarios for years. But what's, you know, with the mergers and acquisitions that we've done over the last couple of years now and the integration of the operations in 2024, you know, we offer a large number of different products and services, you know, across the value chain and drilling and completions that allows us to be able to do more, control more, and improve efficiencies in various aspects of the operation, lower some of the costs for the customer and well construction. And then also, last but not least, just pull production forward. And so combining all these elements like we started doing across drilling and completions in 2024 with P10Advantage, you know, it's been exciting to see how the teams have come together across our different segments and pulled in their services and products to work for improving these types of efficiency. What's interesting is, and in a particular case for the project that we've been on, where, you know, we talk about how we've completed the drilling and now we're moving on to the completion phase, is it's not just the upside that we have on the performance through the arrangement that we have, but also the pull through on services that may not have been part of that package. But when we come together and present a more holistic operational solution for some of these customers, then they're very interested to look at services maybe they wouldn't have used in the first place. So you have pull through on services as well as a potential upside that we may get in the arrangement as well. You know, the types of EMP customers that this is really set up for is not necessarily the large multinationals that you buy gas from at the corner station. You know, those companies have large teams of people that are focused on performance. But when you get into more of the mid-tier EMPs that probably have a lot of acreage, maybe smaller staffs, you know, we can step in and help them and bridge the gaps there and help them look at their performance and see what we can do to improve it. You ask about putting numbers to it. I think it's still early days. But certainly based on the feedback that we're getting today, you know, it has a potential to grow to be a more significant part of what we do.

Appreciate all that color. And as a follow up, when we were sitting here about this time last year, I think there was some kind of hopeful expectation on gas activity and maybe the winter didn't play out quite like we thought then. And LNG projects kind of slid to the right a bit. You know, we're getting closer to that day and curious with your comments and just basically what you're seeing from customers. Is it too early to start seeing guys giving you calls on activity potential at this point or maybe just a little bit color what you're hearing from your customers?

Yeah, I think today, you know, we're hearing various things from customers. We have some very large EMP customers that have, you know, wells behind pipe, behind the wellhead, ready to go. What they're telling us is they're going to be measured on how they bring those wells online. So it doesn't negatively affect natural gas commodity prices. We also have customers that are expanding what they do in some of the deeper, more prolific plays to Hainesville. And they're excited about that, you know, over on the western flank. And so there's various things that are going on. But we're also looking at the macro and the demand and not just what you're hearing from the LNG companies as they prepare their facilities on the go. And so we're looking at the LNG companies, the LNG companies, the LNG companies, the Gulf Coast, but also what the midstream companies are talking about in total natural gas demand that they're seeing from the deliveries that they're going to have to make over the next couple of years. And so while we think 2025 will be relatively steady in the natural gas, there is some potential for upside. But if you're looking at the macro, you know, with the LNG commentary, with the midstream commentary, then it really looks like there's some upside, you know, in the natural gas demand in 26, 27. And so, you know, we're looking at it from the macro standpoint while our customers are managing their budgets this year, but the macro is very favorable longer term.

Got it. Appreciate that color. Thanks, Andy.

Your next question comes from the line of Waycor side with ATB capital markets. Please go ahead.

Good morning. This is a car. And the, is that could you provide some framework to think about how the capital is going to be capex is going to be allocated between the different business lines in 2025?

Yeah, I would say that, you know, let's just talk about the three major business lines. You're looking at probably 35% of it between into drilling, probably about 50% of it into completions with the balance between products and other.

Okay, great. And then in terms of the US drilling business, do you think the margins at this 15 to 50 is that the bottom or do you think there could be further pressure as we get into the Q2 and beyond?

You know, I would say that, you know, where we are in the market with a relatively steady rig count, you know, which is our visibility for 2025 that, you know, pricing for the rigs is relatively steady for the base rig itself. I think our teams have some potential to do some things to maybe slightly improve margin as we work through the year with some technology deployments and some other initiatives. So, you know, we're relatively upbeat, you know, on that business and what we can do there.

Great. And then, you know, on the on the pumping side, any thoughts beyond Q1? Do you expect like some seasonal pick up in just utilization in Q3, Q4? You know, things start to look a little bit better or, you know, change in Appalachia, as well as well during the summer months.

You know, right now, you know, I'll start by saying, you know, Q4 hats off to the team. Performance was a little bit better than we thought it was going to be in the fourth quarter. Then the ramp up in Q1 is probably happening a little faster than we had planned as well. Customers who slowed down in Q4 seem to go back to work very quickly in the first quarter. And so we're seeing that ramp up and activity. You know, we're going to be deploying on stall the horsepower we've got here going into Q2 and Q3 for the projects we're on. We're seeing, you know, increased percentage of simulfrac and more complex type frac operations, a little bit more horsepower and location on a per fleet basis. And, you know, activity is going to be busy. The interesting thing is, you know, in the second quarter, I think we're going to be essentially sold out, not just Patterson UTI, but the industry of equipment that can burn natural gas. And so the market is really going to be tight in the second quarter and the third quarter in terms of, you know, what can burn natural gas. So if there's any, you know, increased call on more equipment, you know, later in the year, that's going to be a challenge for the industry. I think the Q4 is still relatively unknown at this point in the year. You know, does it look like 2024? Does it stay steady through the end of the year based on gas demand? I think that's, we still don't have the visibility on yet, but, you know, overall, you know, our teams are performing well and, you know, we're upbeat for 2025.

Your next question comes from the line of Keith Mackey with RBC.

Hi, good morning. Hey, good morning. Just maybe to start on a broad question of how you see drilling, your drilling versus completion segments, performance unfold through the year. And when you think about the factors like demand, pricing, margins, and then translating that all the way down to EBITDA in a directional sense, which one do you think ultimately does a little bit stronger as the year unfolds?

Well, you know, I'll go first. I'll let Andy Smith weigh in as well. If you look at, you know, the business lines, you know, drilling from an activity standpoint has stayed a little more stable, you know, in terms of contract drilling. And, you know, you've got some relative price discipline in that sector of the market compared to others. On the completion side in 2024, you know, I would say we could have done a little bit better job, and there's things that are happening now to improve that. But also you've had some general market softening as well. So, as we talked about earlier, you know, we're going to be essentially sold out in Q2 and Q3 of equipment that can burn natural gas. And if there's any call on that upside, you know, there's going to be more relative torque on what happens in that completion sector.

Yeah, I don't have a whole lot to add to that. I would say that, you know, just given the nature of the business, as you would expect that, or I would expect that drilling will be relatively stable throughout the year. But you have more upside potential coming out of the completion business now. All of that is caveated by sort of what does the fourth quarter of next year look like. It's kind of similar, and our customers, you know, behave similarly to what they did this year. That could sort of affect the cadence of it. But I do think you have more upside potential in the completion side.

Yeah, understood. Okay. Maybe just going back to the integrated and performance-based contracts. You know, certainly, Andy, hear your comment on that some customers will want this and some may not need it. But certainly, there has been a lot of customer consolidation, and the larger customers are doing a much more, a much higher percentage of overall activity. So can you just give us maybe a little bit more of a sense of what the market size could look like from that offering, both maybe on the drilling and completion side as you build it out?

Yeah, we've been kicking that around and trying to really understand what that market looks like and what we think the uptake is going to be. You know, I think it's early days, but I think over the next few years it certainly has the potential to be in the range of 10 to 20% of what we do. And with the improved profitability, the improved pull through of those types of projects, that's certainly material to the investment community. Again, it's early days and we're still trying to understand, but certainly the feedback has been very favorable and we're pleased with how the teams are performing.

Your next question comes from the line of Sarab Pant with Bank of America. Hi, good morning, Andy and Andy.

Morning, Rob.

Andy, maybe I would just continue with that line of questioning on completions. And like you said, it's really encouraging to see you sold out on the natural gas powered side of the equation for 2Q, 3Q. If I can just continue with that logic and then take it to pricing and think about where pricing is heading from head on. How should we think about the potential, Andy, for you to get back to, let's say roughly third quarter of 2024 kind of profitability in fact? Do you think we can get there by the summer, let's say third quarter, or is that a little bit of a stretch right now?

Well, certainly what you're hearing across the industry is that pricing is coming down in 2025 relative to 2024. Our E&P customers did a good job of taking advantage of the slowdown in Q4 and pushing the pricing across the industry, not just us, but across the industry. But with the market for natural gas equipment across the industry appearing to be sold out in the second and third quarters, that is a positive place for the sector to be. So any call on improved activity later in 25 and certainly in 26 would shift the pricing ability back towards the service side in that respect. Because we'd have to go out and acquire new equipment. We're going to want to do it at a return that makes sense for the shareholders. And so, you know, it's from our side, it's a good position to be in the second, third quarter of the year.

No, that makes sense. You got to take one step at a time. And then maybe one on the overall cost cutting, cost rationalization kind of effort. I'm thinking about the entire business, not just one business. But like you said, on the CapEx front, you did a really good job bringing CapEx down to $600 million this year. How should we think about Andy, maybe Andy Smith, you want to weigh in as well on the overall cost structure in the business, both drilling and Frac? What efforts are you making to further optimize that cost structure?

Yeah, I don't want to get too specific with targets. But as you can imagine, you know, as we've gone through these acquisitions and we've achieved a lot of operational synergies, there are still things to be done around streamlining of systems. You know, certainly, you know, more centralization of some back office processes. And then you have the typical things that we look at just around discretionary cost spend and, you know, where does that fit relative to the opportunity in the marketplace? We should be looking at all of those costs. So there's a lot of things that we're looking at, you know, how we're organized, not necessarily from an operational standpoint, but more from, like I said, those back office functions. So, you know, we do this all the time. But I think right now, given the kind of what I would say is the pretty big change we've gone through as an organization with the two significant acquisitions, you know, it will ramp up quite a bit on the back office side of things. And so we'll see that happening over the course of this year and even in the next year.

Your next question comes from the line of Eddie Kim with Barclays. Hi,

good morning. Just wanted to ask if you could provide some color on what you're seeing on just on the pricing front and the completion business. We've heard from some of your peers that they're definitely seeing some pricing pressure on the frax side of their businesses, even on kind of the tier four dual fuel fleets. Are you seeing something similar there? And when do you expect pricing to kind of bottom out here? Is it a second quarter or third quarter event before some of the gas related activity potentially picks up in the back half of the year? Just some color on what you're seeing on pricing dynamics in the completions business.

Yeah, you know, our EMP customers did a good job at the end of last year, especially taking advantage of the slowdown to put some pressure, not just on us, but across the completions market to, you know, get more value out of us and push our pricing down. So our pricing is coming down year over year, but I, you know, I would say that, you know, 90% of those discussions are in the rear view mirror. The pricing is what it is right now. We're ramping up activity in the Q1. So, you know, we're, it's not a steady state quarter to really see how those numbers look. So I would say, you know, Q2, Q3 ish is probably, you know, how you look at the bottom just, you know, in the financial results. But in terms of negotiations and discussions with the customers, that pretty much wrapped up, you know, at the end of last year. But again, the interesting thing is that, you know, being sold out on 100% natural gas equipment, not just us, but across the industry in second and third quarters, any uptick that we have later this year or certainly into 26 would cause pricing to move up in the completion sector.

Got it. Got it. That's very helpful. My follow up is just on your comments on kind of the mobile power market. You mentioned you currently operate about 150 megawatts to mainly to support your electric frac fleets. One of your peers just announced kind of a big investment they'd be making for the next two years to increase their power gen capacity, but it's clear based on your comments that you're taking a bit of a different and more cautious approach. I guess with that said, could you maybe just talk in broad terms about if there's a certain type of returns threshold or payback period you have in mind, you know, be it, I don't know, three years or five years, at which you would consider deploying capital into the mobile power markets?

Yeah, let me start by saying, you know, we spend a lot of time looking at the power market. We spend a lot of time discussing, you know, the generators that are available from our suppliers at all the different sizes, whether it's gas, re-sip in the small to medium size or in gas turbines in the medium to large size. And, you know, there's a lot of things that are happening. When you start to segregate the market and break it down into different types, you have different generator applications. So, for instance, you know, when we look at the frac power market, we like the turbines and we like the large capacity turbines. And so that's what we're releasing today. In the future, we may decide to own those turbines if it makes sense from a return standpoint. But the turbine is the right application. When you get into the EMP production facilities, you know, if they're in disparate locations in the Permian, you're probably into some smaller or medium sized natural gas re-sip type engine generators, which we also have some experience with. And so, you know, that's a separate application. As I mentioned earlier, what we're not trying to do is just be a commodity generator rental company. You have those companies that are out there already. We're not going to bring value in that sector. But if we're combining, you know, a power solution for one of our customers along with services or technologies that we're already providing in other areas, such as real time monitoring or engineering a custom microgrid form and deploying that. Or maybe a battery storage system. Remember our battery storage systems are designed for hazardous well site operations, so they can fit easily in a production area as well. And you've got our C&G delivery systems. You've got our fuel gas blending systems and which we have, you know, new IP on some of that technology. And so it's really about, you know, can we find the right package that makes sense for a customer? And so we'll continue to explore these opportunities. We're in discussions and we'll continue to explore this and we'll try to do things that bring value for the investors at the end of the day.

Your next question comes from the line of Kirk Hollid with Benchmark. Hey, good morning, everybody.

Morning, Kirk.

A lot to digest here. A lot of good color, a lot of good context, as always. I think I'm going to maybe ask a strategic question and you might not have specific answers, but that's fine. Just want to kind of get a feel for how you're looking at the longer term opportunities for this power business, right? And I know you gave us some insights during the call, but I guess, Andy, I'm just trying to think what kind of level of investment do you think it'll take to get you the scale that you want to capitalize on the opportunity? Again, you don't have to get too specific, but kind of curious about that. And then I guess as a follow up to that, you know, is this a situation where, you know, at some point, you know, this business, you know, becomes its own standalone entity?

Yeah, so let's talk about the growing market demand and really the Permian. You know, the Permian is our backyard. And there's estimates for the Permian growing power demand to be in the range of four gigawatts, you know, over the next 10 years of power demand that would be not connected to the utility grid. Because the utility is going to grow their power supply for our customers out there and for other applications in the Permian. But you've also got this delta that's about, you know, four gigawatts over the next 10 years. It is just that of demand that's not going to be connected to the utility. And so there's going to be multiple opportunities for multiple companies to step in and fill that demand with power generation sources. And what separates us and our capabilities is the fact that, you know, it wouldn't be just us going out and buying a generator and renting it into this type of operation necessarily, but combining it with other things we do to where we can provide a solution that differentiates us from just a standalone generator rental company. And so I think those opportunities are going to exist. Again, it's a longer term play. You know, it's over the next 10 years you're going to have this gap where, you know, power demand exceeds supply from the grid. And so it's not something we're rushing into. It's something that our EMP customers are looking at over the long term as well. And we'll see how it goes. Now, when you talk about scale, it's an interesting discussion because, you know, it's not that we may need to have a certain number of assets to be efficient necessarily. We may take it on a project by project basis where, you know, we're building out in more of a project type, you know, work as opposed to just saying, hey, we need to own a large number of assets to be efficient. And so, you know, we'll keep you posted as we work through this and see how it works out. But again, we're really focused on, you know, what we think is that we need to have a reasonable return for investors as we grow this out. You know, will this be a separate segment someday? You know, I'm hopeful that it will. You know, I think it's we're a couple of years from that. Again, this is a long term play in the Permian for demand for power off grid to grow. So, this is not something that's going to happen right away for us to break it off in a separate segment. But hey, in a couple of years, you know, we might be doing that because it might be material enough that we have to report it separately.

Your next question comes from the line of Jeff LeBlanc with TPJ and Company.

Good morning, Andy and team. Thank you for taking my question. I just had one question regarding retirements in the Frac business. How should we think about retirements over the next several years and when could you move towards 100% natural gas burning equipment? Thank you.

Yeah, I mean, look, we will continue. We still operate some older equipment and tier two equipment, you know, non PGD type stuff. And we'll continue to look to retire that stuff as it kind of reaches the end of its life. We're not going to take it out of service if it's working. But obviously, we're not going to invest a lot in kind of replenishing that level of equipment either. I don't have a specific horsepower number that I want to get tied down to right now, but certainly that stuff's reaching the end of its life over the next two, three years or so. And so we'll continue to pull that out and then replace it with something that is more fit for the current, you know, again, opportunity set in the market, which is natural gas burning.

Your next question comes from the line of Doug Decker with Capital One Securities.

Thank you. I want to circle back on the US drilling margins. Andy, you characterized pricing on the base rigs is stable. You have potential upside on technology deployments. And then on the same time, you're streamlining costs, payroll, taxes declined in the second quarter. I'm just trying to get a sense for what factors do you see keeping one cue from being the margin trough in the business?

You know, there's several things that we're working on. There's the pace of, you know, as we deploy new technology out on the rig systems, there's the pace that we're going to move at streamlining some cost structures there, because we certainly want to protect performance and efficiency efficiency at the same time. So we'll just see how it plays out. But overall, through the year, I think that you'll see some improvements.

Make sense. Go ahead.

Thanks.

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

Thank you, Rebecca. I want to thank everybody that dialed in today for our call. Again, I want to thank all of our employees, our team at Patterson UTI for everything they did to make 2024 a great year. And we look forward to a great 25 as well. So thank you very much.

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