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Operator: Thank you for standing-by. My name is Van, and I will be your conference operator today. At this time, I would like to welcome everyone to the Patterson-UTI First Quarter 2025 Earnings Conference Call. [Operator Instructions] Thank you. I would now like to turn the call over to Michael Sabella, Vice President of Investor Relations. Please go ahead.

Michael Sabella: Thank you, operator. Good morning, and welcome to Patterson-UTI’s earnings conference call to discuss our first quarter 2025 results. With me today are Andy Hendricks, President and Chief Executive Officer; and Andy Smith, Chief Financial Officer. As a reminder, statements that are made in this conference call that refer to the Company’s or Management’s plans, intentions, targets, beliefs, expectations or predictions for the future are considered forward-looking statements. These forward-looking statements are subject to risks and uncertainties as disclosed in the Company’s SEC filings which could cause the Company’s actual results to differ materially. The company takes no obligation to publicly update or revise any forward-looking statements.

Statements made in this conference call include non-GAAP financial measures. The required reconciliation to GAAP financial measures are included on our website, patenergy.com and in the Company’s press release issued prior to this conference call. I will now turn the call over to Andy Hendricks, Patterson-UTI’s Chief Executive Officer.

William Hendricks: Thank you, Mike, and welcome to our first quarter earnings conference call. The first quarter of 2025 unfolded largely as anticipated with steady drilling activity across U.S. shale and a strong recovery in completions activity following fourth quarter E&P budget constraints. As the first quarter progressed, we started to see some positive momentum in the natural gas basins and that momentum has carried into the second quarter. In oil basins, we have continued to see steady demand as our customers monitor recent macro events. At Patterson-UTI, our focus on optimizing our core operations and disciplined capital allocation is delivering results. Our scale, our strong customer relationships and comprehensive service and product offerings set us apart operationally, positioning us for sustained success.

At the core of our strategy is our commercial offering that can deliver a suite of services and products that is unique to Patterson-UTI with an operational footprint that allows us to touch more of the well site than nearly any of our competitors. We believe this can enhance efficiency and unlock value for our customers while positioning us for relative market outperformance. All Patterson-UTI segments performed well in the first quarter, which is a testament to the quality of our assets as well as our people and our technology. Our integrated agreements in both the drilling and the completion businesses leverage our full capabilities and our commercial strategy is benefiting the entire company. We continue to believe that controlling more of the well site will allow us to drive greater efficiencies for our customers, while also maximizing returns for our investors.

The initial fully-integrated P10 Advantage project exceeded expectations, delivering performance bonuses and accretive margins for Patterson-UTI while also delivering a better outcome for the customer, truly a win-win. We expect integrated work on both the drilling and completion side will continue to grow as a proportion of our overall business. For U.S. Shale, we believe that service companies that can deliver value-accretive services, not just the lowest price will be positioned for sustainable returns. Our differentiated position in the market is difficult to replicate and we remain confident in our ability to drive long-term capital-efficient value for both our customers and investors. Our size, scale and breadth of our offerings positions us favorably with larger, better capitalized customers that maintain a long-term strategic focus and are less reactive to short-term moves in commodity prices.

We have an outsized exposure to the industry’s largest and most stable operators relative to the broader market. Feedback from our largest customers so-far has focused on goals for long-term value-creation rather than short-term reactionary decisions. These objectives are fully aligned with our own, providing a strong foundation for collaborative, sustainable relationships. Financially, our strong balance sheet and liquidity provide the flexibility to pursue high-return opportunities and we will remain targeted with our capital deployment and protect our capital structure. We closed the quarter with $225 million in cash and an undrawn $500 million revolver, low leverage and an investment grade credit rating with an outlook that still sees significant uncommitted free cash flow in 2025.

From a capital perspective, we are operating from a position of strength and using our capital to drive long-term shareholder value is our key priority. On the macro, external factors have created an uncertain outlook, although we have yet to see any impact to activity levels from recent commodity volatility. Regardless of how the market develops, Patterson-UTI is prepared to adapt and execute our strategy across a range of commodity price environments. On the oil front, recent commodity softness created by macroeconomic concerns has introduced some uncertainty. If oil prices remain near current levels for an extended period, we could see some of our customers reevaluate their plans. At present, operations remained stable. On the natural gas side, the outlook is increasingly constructive.

We have added multiple rigs and frac fleets in natural gas focused basins already this year and we continue to believe that the industry needs higher natural gas drilling and completion activity over the next several years to satisfy a call for more U.S. shale natural gas production to supply global LNG and domestic demand. Our U.S. contract drilling business delivered another quarter of strong results with sequential improvements in average daily rig count and margins and higher returns. The performance is a testament to the quality of our drilling assets combined with the people and processes we have in place, allowing us to deliver for our customers and show them value over lower priced options. Patterson-UTI’s Cortex automation platform is setting a new standard in drilling automation by integrating advanced data science throughout its applications.

By leveraging real-time analytics, pattern recognition and intelligent control logic, Cortex delivers both high operational efficiency and an intuitive user experience. The platform automates key functions such as auto drilling and directional control, enabling drillers to focus more on critical safety and performance measures. With Cortex, the operators benefit from greater repeatability and a scalable advantage that expands across multiple rigs and our investors are seeing the benefit through higher returns and margins. We believe our technology allows us to drill faster, better and safer wells for our customers. We believe that our Apex drilling rigs are the premier capital assets in the drilling market and that our people and our technology are critical to unlocking value for our customers and investors.

We continue to deliver improved cycle times and the relative demand for our rigs and stability of our margins confirms our customers are recognizing our unique capabilities. Our Completion Services segment experienced a strong rebound in the first quarter as expected. Demand for our frac services was healthy, supported by favorable commodity prices across both oil and natural gas basins. Notably, as the first quarter progressed and activity ramped up quickly, we saw growing demand in natural gas basins. The Haynesville was the biggest beneficiary so far, although we would expect to see gains in other regions if macro conditions hold. With our solid footprint in the key natural gas plays, we are well-positioned to benefit as demand improves.

We continue to make technical strides in our completions business. Our fleet of Emerald 100% natural gas-powered equipment is performing exceptionally well, delivering strong results and receiving positive feedback from our customers. In the first quarter, we again saw our Emerald fleets grow as a proportion of our overall frac activity with increasing demand for larger Emerald simul frac operations. We believe we operate one of the highest quality fleets in the industry today. Importantly, we continue to high grade our asset-base at a measured pace, remaining disciplined with our capital, generating significant free-cash flow and returning substantial cash to shareholders at the same time. Balancing between new technology investments and capital stewardship remains a cornerstone of our capital allocation strategy.

We expect our natural gas-powered equipment will continue delivering strong returns through the cycle, including our dual-fuel equipment. More than 80% of our active fleet can be powered by natural gas. Across the industry, we believe equipment capable of running on natural gas is effectively sold out, a clear indicator of both current demand and the value of our investment in this technology. Our Drilling Products segment continues to perform well in all regions and the team has done a great job in anticipating customer needs by delivering the highest quality innovative products in areas where we see the best opportunities to improve efficiencies. Our new product innovation revenue has continued to grow at strong returns, partly driven by our new Maverick cutter and drill bit designs.

Overall, we are pleased with the Company’s performance in the first quarter across all segments and remain focused on execution for our customers and investors while outperforming the market. I’ll now turn it over to Andy Smith, who will review the financial results for the first quarter.

Andrew Smith: Thanks, Andy. Total reported revenue for the quarter was $1,281 million. We reported a net income attributable to common shareholders of $1 million. Adjusted EBITDA for the quarter totaled $251 million. Our weighted-average share count was 387 million shares during Q1 and we exited the quarter with 386 million shares outstanding. During the first-quarter, we generated $51 million of adjusted free cash flow. We saw a working capital headwind of roughly $37 million in the first quarter, which is typical of our business in the first-half as we come out of the fourth quarter slowdown. We expect working capital will be a tailwind in the second-half of the year. During the first quarter, we returned $51 million to shareholders, including an $0.08 per share dividend and $20 million for share repurchases.

Over the 18 months from September 30, 2023, which was the first reporting period following the close of the NexTier merger and Ulterra acquisition, through March 31, 2025, we have used approximately $387 million to repurchase shares and we have reduced our share count by 8% since we closed those transactions. This is in addition to reducing net-debt, including leases by over $200 million since that time and paying a dividend that is currently an annualized 5% of our share price. In our Drilling Services segment, first quarter revenue was $413 million and adjusted gross profit totaled $165 million. In U.S. contract drilling, we totaled 9,573 operating days. Average rig revenue per day was $35,700 with an average rig operating cost per day of $19,600.

The average adjusted rig gross profit per day was $16,200. On March 31, we had term contracts for drilling rigs in the U.S. providing for approximately $407 million of future day rate drilling revenue. Based on contracts currently in place, we expect an average of 62 rigs operating under term contracts during the second quarter of 2025 and an average of 35 rigs operating under term contracts over the four quarters ending March 31, 2026. In our other Drilling Services businesses, which is mostly international contract drilling and directional drilling, first quarter revenue was $71 million with an adjusted gross profit of $10 million. Our U.S. contract drilling business is the majority of our Drilling Services segment and historically, we have disclosed revenue per day and adjusted gross profit per day specific to this business line.

Moving forward, while we continue to report U.S. contract drilling operating days, we will no longer report revenue per day or adjusted gross profit per day. As we further integrate our drilling operations and shift more towards performance-based agreements, we no longer plan to isolate and report individual components of the segment. Instead, we will focus on providing details at the segment level to better reflect the integrated nature of our operations. For the second quarter, in Drilling services, we expect a relatively steady rig count compared to the first quarter. We expect adjusted gross profit to decline slightly with the sequential change driven by a reduction in average contracted revenue as legacy contracts roll as well as some normal seasonal increase in costs.

Revenue for the first quarter in our Completion Services segment totaled $766 million, with an adjusted gross profit of $108 million. Activity increased from the fourth quarter slowdown and we saw strong demand and high utilization with increased activity sequentially in both oil and natural gas basins. Average pricing was down compared to the fourth quarter, although we partially offset lower pricing with some cost reduction initiatives. Pricing was mostly steady throughout the quarter and we exited the quarter with roughly the same pricing as we entered. For the second quarter, we expect Completion Services adjusted gross profit to decline slightly sequentially. Currently, activity levels are steady compared to where we exited the first quarter, and we have not seen any change in strategy from our customers.

However, if oil prices remain near current levels, we could see some white space later in the quarter. First quarter Drilling Products revenue totaled $86 million with an adjusted gross profit of $39 million. Drilling Products revenue was relatively steady in all major geographic regions compared to the fourth quarter. Segment adjusted gross profit improved on lower operating costs which was driven by operational efficiencies. For the second quarter, we expect Drilling Products adjusted gross profit to be relatively steady sequentially with steady results in the U.S. We expect normal seasonal activity declines from Canadian spring breakup to be mostly offset by increase in international on a sequential basis. Other revenue totaled $16 million for the quarter with $7 million in adjusted gross profit.

Subsequent to the close of the first quarter, we absorbed a portion of the assets of our Great Plains Oilfield Rental business into our other business units and divested the remainder of the business. Great Plains comprised roughly two-thirds of the revenue and adjusted gross profit in our other businesses line items on our income statement. As a result, we expect other adjusted gross profit in the second quarter to decline proportionally as compared to what we reported in the first quarter. Reported selling, general and administrative expenses in the first quarter were $67 million. For Q2, we expect SG&A expenses of approximately $65 million. On a consolidated basis for the first quarter, total depreciation, depletion, amortization and impairment expense totaled $232 million.

For the second quarter, we expect total depreciation, depletion, amortization and impairment expense of approximately $230 million. During Q1, total capex was $162 million, including $73 million in Drilling Services, $62 million in Completion Services, $18 million in Drilling Products and $8 million in other and corporate. As a reminder, our full year 2025 net capital budget was set at approximately $600 million. Based on what we see today, with our activity levels steady into the second quarter, we are not revisiting our budget. However, we also feel it is important to point out the flexibility we showed last year in adjusting our budget to changes in our outlook. The lion’s share of our CapEx budget is for maintenance and repair of our equipment and if for some reason the activity outlook changes from our base case, we have the flexibility to decrease our budget just as we have done in the past.

We closed Q1 with $225 million in cash on hand. We do not have any senior note maturities until 2028. We do not have anything drawn on our $500 million revolving credit facility. We still 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 share buybacks and dividends. Free cash flow is likely to be weighted to the second-half as working capital needs decrease. Our Board has approved an $0.08 per share dividend for the second-quarter of 2025 payable on June 16 to holders of record as of June 2. I’ll now turn it back to Andy Hendricks for closing remarks.

William Hendricks: Thank you, Andy. And I want to close with a few key takeaways. We are very pleased with our performance in the first quarter, where each of our core businesses performed very well. As we enter the second quarter, we are operating at a high level. At Patterson-UTI, maintaining a strong balance sheet has always been central to our strategy. It has enabled us to navigate periods of uncertainty and positioned us to act decisively when opportunities arise. Today, we have an investment grade credit rating and net-debt, including any operational or financial leases is just 1 times trailing 12 months adjusted EBITDA. We have no material near-term debt maturities and robust liquidity with a sizable cash balance and an undrawn revolver.

We expect to generate another year of solid adjusted free cash flow in 2025 and our capital allocation plans are flexible. We will look to use our capital to maximize our long-term returns. Operationally, we remain focused on enhancing our core businesses through capital efficient initiatives. We believe we should outperform the broader market driven by our differentiated product offering and unique commercial strategy. At the same time, we continue to pursue opportunities to right size costs and drive greater corporate-level efficiency. And finally, on the macro, while the outlook in the oil markets remains somewhat uncertain, we are encouraged by early signs of recovery in the natural gas basins with some activity increases that were greater than previously anticipated.

While customers remain cautious, it is clear to us that meaningful increases in drilling and completions activity in natural gas basins will be required to meet growing commodity demand, particularly as U.S. natural gas plays an expanding role in supporting global LNG needs. Overall, current activity levels remain steady and although oil commodity markets have been volatile in recent days, we remain optimistic about delivering another solid year of strong operational performance and robust adjusted free cash flow. Patterson-UTI is in a great position for the current market and ready for any future activity increases in the natural gas basins. With that, we’d like to thank all of our employees for their hard work, their efforts and successes to drill and complete wells safely and efficiently each day.

We’d now like to open the lines for Q&A. Van, we’ll hand it over to you.

Operator: [Operator Instructions] Your first question comes from the line of Arun Jayaram from JPMorgan. Please go ahead.

Arun Jayaram: Good morning, Andy and team. Andy, first, I wanted to talk a little bit about the evolution of your commercial model and some of the integrated services you’re offering. As I cover the E&Ps as well and have noted how you are making some inroads with some of my key coverage. So, I was wondering if you could maybe comment on what you’re kind of offering at the well side and what are some of the benefits that you can give E&Ps as they’re all focused on efficiency and lower-cost, particularly in these times?

William Hendricks: Hi, Arun, good morning. Yes, it’s been an evolution for us. It’s also part of the evolution of the company as we’ve grown, service lines and products as part of what we can offer to the E&Ps. So, we now have a breadth of offering that’s really unmatched in U.S. shale today from drilling rigs to cementing services to directional drilling, to drill bits during the drilling operations. And then on the completion side, it’s not just hydraulic fracturing, it’s wireline, it’s logistics to move sand and equipment. It’s logistics to move natural gas from compression stations and bring it out to the field with fuel gas blending and, and so many different things. And then when you connect the digital aspect across all of that and we can look at all the data across everything we’re doing, we can pull all that together for the E&Ps and help them be more efficient at what they’re doing.

And certainly, we have a number of E&Ps that recognize our ability to do that. And we see – we’ve seen a growing number that have some interest to talk to us about doing more integrated type projects where we can take advantage of having all the digital data and systems that we can provide and then pull all that together into operations in the field.

Arun Jayaram: Great. And my follow-up is just a little bit, Andy. How are you thinking about, replacement CapEx, on the frac side, obviously, you’re highlighting really strong demand trends for your natural gas burning equipment on the Emerald side. But how are you thinking about, you’re constantly in a bit of a replacement cycle, but how are you thinking about replacements? And then maybe as you ponder that question, any kind of impacts around tariffs as we think about component costs and things like that?

William Hendricks: Yes, sure. So, part of our CapEx budget includes more of the Emerald 100% natural gas driven equipment. And so while we continue to maintain everything that we own, we certainly recognize that the older equipment that we’ve owned for a while is not necessarily going to be the most interesting. But what is interesting is the uptick and the uptake on our activity with the Emerald 100% natural gas systems. And so you’ll see us grow the amount of horsepower over the next few quarters and especially with an addition towards the end-of-the year of a full fleet of increased capability on the Emerald 100%. And that’s still part of the CapEx budget. So, no change in that CapEx budget. And we expect even with the potential fluctuations in the market, that will still be the most attractive equipment to – for the E&Ps to maintain their level of efficiencies that they’re looking for.

Not just operational efficiencies, but cost efficiencies as well. Andy, do you want to add anything to that?

Andrew Smith: Yes, Arun, I would just say that look on, on kind of the replacement as you asked about, I would say that I would describe our pace as we’re going to be pretty measured over, again the foreseeable future. And then on the tariff side, it’s still pretty early to put too fine a point on it, so I won’t. But I will say that we’re trying to cultivate where we feel like we need to alternative suppliers and also all of our groups are kind of keenly focused on, are there costs that ultimately, if they show-up, we can pass-through through pricing. So, I would say we’re addressing it, but right now, it’s probably a little too soon to put a fine point on it.

Arun Jayaram: All right. Great. Thanks, gentlemen.

William Hendricks: Thanks.

Operator: Your next question comes from the line of Scott Gruber from Citigroup. Please go ahead.

Scott Gruber: Yes, good morning and nice quarter, especially in completion. I guess, I’m a bit confused by the completion guide, typically activity ramps up over 1Q such that you just hold the exit-rate into the second quarter, completion tends to rise a decent amount, call it, mid-single digits historically. But you guys are forecasting a slight profit decline, can you provide some color just on, how much white space you’re kind of baking into completion later this quarter? And are you getting any indications that level will materialize or is this just, some conservatism that you’re building in right now just given the pullback in crude? Some color there would be great.

William Hendricks: Yes, good morning. So first, I mentioned that the first quarter actually ramped up probably faster than we thought it would, hats off to our teams in the completion segment that we’re able to pull everything together from the – basically the rapid slowdown we had in the fourth quarter when E&Ps were exercising budget constraint then. So, things really, really ramped quickly in the first quarter. And so, we hit a level of activity that, I think at the end of the quarter even surprised us and even the first part of the second quarter. As we look across the quarter, it’s relatively steady from an activity level standpoint, although, we are being a little bit conservative as to how we look at the end of the quarter. We might see a little bit of white space based on some decisions some of our customers make, but, it’s really kind of relatively steady at the same time.

Scott Gruber: Got it. And then you mentioned, pretty steady demand on the oil side here, but we do know that the E&Ps have been, planning for a range of potential outcomes on the oil price side. And there seems to be that, if, if, if oil sits here in the low 60s, there’s probably some adjustment. Do you have a sense, Andy, for just how large that adjustment could be if oil is just, call it, flat from here? And I guess it’s a two-part question. One is how large could that adjustment be for the market? And then, as we saw last downturn during the pandemic, you guys picked up a good amount of share. So, two is kind of, what could that adjustment be for Patterson specifically?

William Hendricks: Yes. So, when we, when you look at the portfolio of E&Ps that we work for, about 60% of our revenue comes from the 15 most active E&Ps in the U.S. And so, we’re heavily weighted to, essentially people that have large programs in terms of multiyear plans for what they want to do. And so, what we’ve seen is that, really almost every E&P customer that we have has been monitoring the situation. I think it’s safe to say that what’s happening in the market today is, unlike some of the previous, softenings that we’ve had or changes in commodity prices and the executive teams from these companies are, are really kind of waiting to see what happens and if there is any, recovery in oil to the upper 60s. I think when we see oil in the upper 60s, that pretty much normalizes everything for what we’re doing.

In the lower 60s, we could see some softening if it stays in there. But I would still just refer to it as softening in the market. It doesn’t change our ability to continue to produce strong free cash flow in the year. Certainly, there would be some E&Ps that make some decisions to reduce their budgets, but even in the low 60s, I wouldn’t expect a drastic response from the customer base that we work for.

Scott Gruber: I got it. Appreciate it. Thank you.

Operator: Your next call comes from the line of Atidrip Modak from Goldman Sachs. Please go ahead.

Atidrip Modak: Hi guys, good morning. Andy, you noted you’ve started to see some momentum in the gas basins, but you also mentioned that some customers are cautious. So maybe help us understand that a little better and how we should think about the incremental rigs or fleets or maybe utilization trends for the remainder of the year?

William Hendricks: Yes, I would say in the gas basins, our expectation right now is that things are going to remain relatively steady. I mean, we seem to be, with the commodity prices in gas approaching, the shoulder season and it still seems to be at a reasonable level to keep, our E&P customers in gas relatively busy. So, I don’t expect any real change in what we’re doing in natural gas at today’s commodity price. It did ramp-up a little bit faster in the Haynesville than we thought, especially on the completion side. We did deliver a couple of rigs, but they were – they had been in the plan, on a longer-term plan where we had done some customization to some specific specifications on those drilling rigs, but completions ramped-up a little bit quicker.

So, we’ve been very busy out of our East Texas operations covering the Haynesville more than we thought. So – but at today’s commodity, I would expect it to remain relatively steady. And, of course, everybody would be watching the commodity price in that area. The forward strip on natural gas still looks good. And I think that a number of our customers also did some hedging earlier on in the year at higher natural gas prices. So, financially our customers in natural gas seem to be very healthy.

Atidrip Modak: That’s very helpful. And then you guys spoke about the flexibility around CapEx, but you also mentioned that you have the opportunity to right size costs and drive corporate efficiency. So maybe if you can provide any color on that depending on how the year plays out?

Andrew Smith: Yes. On the cost side, I would say, look, all of our operating units are very focused on costs and particularly around support costs and not only out at the field level, but also corporately. So, I think you’ll see progress on that front kind of ratably throughout the year. I don’t want to give any targets right now, but certainly, I think you’ll see our costs come in somewhat over the course of this year.

Atidrip Modak: That’s very helpful. Thank you.

Andrew Smith: Thanks.

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

Saurabh Pant: Hi, good morning, Andy and Andy.

William Hendricks: Good morning, Saurabh.

Saurabh Pant: Andy, I want to just maybe ask for your perspective on the drilling versus completion side of things because you are the only one who does both and both had scaled. Well, from your perspective, Andy, right, when you’ve seen times like these uncertainty, some risks to E&P, CapEx, activity, right, how do you think drilling and completions would trend relative to each other. Is there a scenario under which you think completions falls faster than drilling and we see some E&P building ducks, right? But just maybe your thoughts on how you think that this plays out?

William Hendricks: I think this, this is an interesting time in the industry. The way the commodity prices have been moving and you’ve had this kind of separation between how oil is moving versus how natural gas is moving. So, you really have to look at the two markets somewhat separate. Like, I really believe that where natural gas is trading today, it will keep us steady in that market. So, I’m not expecting any real change there. And the things that are happening at the macro-level and the economy don’t really seem to be moving the natural gas number as much as it has on the oil. So, I do expect relatively, steady markets there. And we have a very large position in natural gas, not just the Haynesville, but of course, the Northeast.

So with the increasing activity that we’ve had in that market in the first quarter, our exposure to the gas has moved up from 25%, maybe closer to 30% now. And so, we’re well weighted to the natural gas and the steadiness of that market. On the oil side, of course, we see more fluctuation. We’ve seen it move around. We’re in the low 60s right now for WTI. That could cause a slight softening in the market. And so, if we see it trend that way as a softening, maybe there’s a little bit of a slowdown in drilling and completion at the same time, but I wouldn’t necessarily expect those to diverge much or see any duct building in that area. But again, where we are trading at WTI, potential for a softening, but I think we just have to wait for the macro and see how the commodities markets play out.

Saurabh Pant: Right, right. No, very interesting dynamic for sure on the gas sources oil side, Andy. And then a second question for me, Andy, is on pricing, right. The industry has been really disciplined, done a really good job on pricing this cycle versus prior cycles, right, and we know pricing hurts profitability much more than activity does, right? So, in this kind of environment on the $60, low $60 oil price, how should we, as investors think about pricing risk going-forward through the remainder of the year?

William Hendricks: Yes, on the drilling side, we did have some contracts that are going to roll and some adjustments in the market that we’ll make there. So, it’s coming down just a little bit, but not much, low single-digit percentile. On the completion side, the majority of those agreements and contracts were all negotiated at the end of last year and are really kind of locked-in place for where we are right now. So, I’m not expecting any, any real change on the completion pricing. On drilling products, our product pricing has been inching up with the increased percentage of new technology that we’re running there, especially with the Maverick cutters and drill bit design that’s setting new records out in the field, especially in the Permian.

And I’ll even just mention our directional drilling sub segment, which has shown increased reliability in equipment over the last year and a half and that’s really being recognized in the market. We’re getting premium prices for our, our high-performance drilling motors and the reliability of the MWD. We’ve actually, increased market-share and margin in that business over the last year. So I’m feeling really good about all of our businesses. I know there’s some concern about the macro out there. But I think natural gas for us is steady, maybe there’s a little bit of softening in oil business, but I think we just have to wait and see.

Saurabh Pant: Yes, yes. No, that sounds very resilient. Like Andy said, the 5% dividend yield and if there’s not that much downside, clearly, the market will be looking for too much downside, but we’ll see. Okay, Andy, I’ll turn it back. Thank you.

William Hendricks: Thanks.

Operator: Your next question comes from the lines of Eddie Kim from Barclays. Please go ahead.

Eddie Kim: Hi, good morning. Just wanted to ask about potential activity declines in the second-half of the year. You mentioned that if oil remains at current levels, customers could reduce activity in the oil basins. And so, current U.S. land rig count stands at about, 570 rigs or so today. Could you see maybe 20 or 30 rigs come out-of-the market by year-end if oil kind of holds in this low 60s level? Just wanted to get your thoughts there.

William Hendricks: Yes. So, like I said, if oil stays at this level in the low 60s, I think you’ll see a softening in the activity. But the other aspect of this is, you’re going to see a bifurcation in the market and what will happen is you’ll see, some of the lower spec rigs come down first even before ours have. We’ve seen this in previous years, previous quarters when we’ve had these softening in the market. And so, while the overall, rig count that everybody looks at may come down, the highest spec rigs don’t necessarily come down at the same rate. And so, as I mentioned, the majority of our revenue comes from the 15 most active operators who have multiyear programs. And so, you may see some of the smaller private equity-backed E&Ps, reduce their budgets quickly to protect cash, but that’s not necessarily our customer.

We don’t work for a lot of those types of E&Ps. And so, you’re going to see this bifurcation in the market. And for us, that’s on the drilling and the completion side. So, you’ll see E&Ps in the Midland Basin maybe slow-down quickly, but that’s not where we do a lot of completion work. And so you’ll see some of the smaller companies slow-down, but the larger, higher-tier companies will stay more relatively busy compared to them.

Eddie Kim: Got it. Thanks for that reminder. My follow-up is just on the distributed power market. Last quarter, you highlighted that you’re prepared to deploy capital to satisfy, growing power demand and the customers were increasingly looking toward electrifying compression systems and the production pads. And just in light of recent events, do you think there’s maybe less urgency from the E&Ps to electrify those systems than there was three months ago and, and has that kind of opportunity set-in the distributed power market maybe even pushed out a bit?

William Hendricks: So, we’ve never earmarked any specific amount of capital for power, but what we do is we analyze each of the projects that come our way. And we’ve had a number of discussions with our E&P customers, both on looking at production facilities and midstream facilities and trying to see, if there’s something that we can provide that’s differentiated in those markets. And in some cases, there is. And so, we’ll continue to look at those projects. But again, we analyze those on specific case-by-case basis. We well – we very well understand our return of capital hurdle and, our need to, produce a return. And we’ll only earmark capital for those projects if we think it makes sense.

Eddie Kim: Got it. Got it. Appreciate the color. I’ll turn it back.

William Hendricks: Thanks.

Operator: Your next question comes from the line of Keith Mackey from RBC Capital Markets. Please go ahead.

Keith Mackey: Hi, good morning. First wanted to start out on the performance-based contracts. I know there’s some commentary about focusing there. Can you just talk about the adoption of performance-based contracts? What type of uplift you’re seeing? And ultimately, how should the market assess the success of these given, that you’re not going to report the revenue per day anymore? And, and finally, do you see the performance-based contracts extending maybe beyond drilling into completions and, and, and in a larger adoption model? Any, any color around that stuff would be helpful.

William Hendricks: Yes. We’ve been excited about the performance that we’ve been able to provide in running these types of operations where we’ve integrated the services. We’ve added services in some cases where, an E&P might not have run, the majority of our services. And then using the digital aspect of everything we do to improve the efficiency and improve our – not just our chance of success, but the overall outcome for the E&P as well. So, we have seen that gain momentum in terms of discussions. We’re up to around 10% of what we do has integration in it these days and performance basis on these types of contracts. I think that we will continue to grow, but this is a multiyear process, and also depends on a little bit of the macro and any headwinds that we have there.

But we’re thinking about this in terms of the long-term. And we see our Drilling Products group continue to set records with new technology and that’s at the front-end of what we’re trying to do with integrating things and proud to have them as part of what we do because, if the industry is going to continue to drill faster and complete faster, we need to be at the leading-edge of that and that will help us maintain and increase our market share and improve our opportunity for improved margins as well as we, can provide positive impacts to our customers. So, I think that will continue to grow. It’s hard to say exactly what pace that is, but again, we’re taking a multi-year look at this.

Keith Mackey: Okay, that’s helpful. And maybe just around the Q2 guide, I know you expect drilling and completion to be down slightly. Hoping you can put a little bit more of a goalpost around that in terms of the percentage decline that you’d expect, slightly to approximate.

Andrew Smith: Yes, Keith, I would say, low-single – low-to mid-single-digit declines.

Keith Mackey: Okay, got it. Thanks very much.

William Hendricks: Yes, Keith, in terms of drilling, it’s really about just making some market adjustments with some contracts rolling and in completions, it’s just a little bit of uncertainty at the end-of-the quarter on how much white space we’re going to have. But again, just a slight softening.

Keith Mackey: Okay. That’s helpful. Appreciate it.

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

Stephen Gengaro: Thanks. Good morning, everybody. I guess just two quick ones from me. The first, when you talk about the legacy drilling contracts rolling-off, can you give us a sense for kind of the price difference between where they are versus where the spot market is?

William Hendricks: I think that it really depends on when we sign some of these. Anything, of course, it’s a year and a half or more is going to be signed when the market was at a higher level of activity versus, say, six months ago. So, it’s hard to put a number just on that in general, but I’d say that it’s less than a 10% adjustment.

Stephen Gengaro: Okay, great. No, that helps. And then the second question, it has to do with sort of capital allocation and, and how you’re sort of thinking about the world is as you look out to the second-half, I mean, if we do see a reduction in activity and it seems like a lot of the service companies are talking about the U.S. being down 10% to 15% this year, give or take. And I know your customer base sort of maybe helps mitigate some of that. But is there a – how do you sort of balance buying back stock with, with sort of balance sheet strength over, over the next year? Have you guys sort of thought about how to balance that based on how the market evolves?

Andrew Smith: Yes, Stephen, I think as you get into that and, and look, it’s – as you become more certain about what not only the sort of magnitude and the longevity of any downturn is going to be. I think you can be pretty specific about what you want to allocate to which I think right, I think the uncertainty is, is the tough thing and not knowing how long something will last and how deep it might go. And so, I think in times of uncertainty, people tend to maybe fall back and, and maybe protect their balance sheet a little bit more, but once you have a little bit more visibility, you can be pretty constructive about your capital allocation plans. And again, I don’t know what the second-half is going to bring specifically yet, but if we get into something where the outlook is a little bit more certain, I think we can be pretty constructive.

Stephen Gengaro: Okay.

William Hendricks: We are committed to, returning 50% of our free cash flow to shareholders and we certainly stand-by that. We may be, sitting on more cash than, than that this year. And if we don’t have a need for that cash, we’ll look to return that to shareholders as we’ve done in the past.

Stephen Gengaro: Okay, great. And then if you don’t mind, one final one. Just the decision on the drilling side to stop breaking out some of the components, including revenue per day. I mean, just can you talk a little bit about kind of why that is? I mean, I kind of understand it at a high-level, but it always, always sort of worries I think people from our side when you disclose less. And I’m just kind of curious as to how you came to that conclusion and now is the right time to do that?

William Hendricks: I’ll start with and then I’ll let Andy fill-in some of this as well. We’ve looked at this for years. We’ve been disclosing more than our peers have for years. And as we’ve continued to add service lines and, and integrate things, it just doesn’t make sense anymore just to break-out a sub-segment like we have. We’re doing more integrated type work. The segment for Drilling Services contains more than one business line now, so, we’re just trying to align the reporting with how we’re operating the business as well.

Andrew Smith: Yes. I would just add to that. I think, I think the more you focus on, one individual metric, whether it’s a day rate or something like that, it sort of undervalues the integrated offering and, and really the performance-based offering that we’re, we’re trying to, offer to our customers. So, we think it’s the right thing. And again, it aligns us a little bit more with, with what some of our competition is doing as well.

Stephen Gengaro: Okay. No, that’s fair. Thank you and thanks for all the details.

Andrew Smith: Thanks.

William Hendricks: Thanks.

Operator: Your next question comes from the lines of Dan Kutz from Morgan Stanley. Please go ahead.

Dan Kutz: Hi, thanks. Good morning.

William Hendricks: Good morning.

Dan Kutz: So, I wanted to – Andy, you kind of made some comments earlier about the kind of relative resilience of the higher-spec assets that the Patterson fleet is, is comprised of both on the drilling side and the frac side. I wanted to dive in a little bit more on the drilling side. So, so, I think that you guys have done a great job of highlighting the fact that they’re – that potentially the old super-spec rig definition was perhaps a bit antiquated and, and, and you guys I believe coined the term Tier-1 super-spec and, and have kind of consistently updated us on, on the number of rigs that you have that meet that definition. I was hoping maybe you could if there’s any chance you have an estimate of what maybe that Tier-1 super-spec class would look like for the broader industry, maybe what supply and, and demand of what you guys define as Tier-1 super-spec looks like, at an industry level? Thanks.

William Hendricks: Yes, good morning. So, over the last decade, that’s just been a moving description that’s gone from high-spec to super-spec to Tier-1 super-spec as the specifications on, on the rigs have, have gone up. And, we’ve even deployed some rigs that we’ve customized for some key customers that I would say are even at a higher-spec than what we’ve traditionally called as Tier-1 super-spec. So, I’m not sure we’ve got good definitions anymore that describe what we do. It’s really about performance at the end-of-the day, and it’s about what our people do with that technology in the field and the operations. And that’s what, matters at, at the end. And so, I think as an industry, we’re going to look less at trying to say, it’s a certain horsepower, a certain load capacity or pump size or anything like that and really look at the performance of the entire package and what we’re doing.

And you combine that with digital and what we do in our P10 performance center, which we will unveil the new one here soon to the public that we’ve built-out on the entire third floor of the building. When you combine all that, at the end-of-the day, it’s really about performance and when I get back to talking about, majority of our revenue comes from the largest operators in the U.S. and that’s for a reason because we’re delivering performance for these operators. They know that we’re going to be efficient. They know that we’re going to continue to focus and work to improve what they do at the same time. And so, I don’t think we can really kind of break it down into a name on the specification anymore like we used to.

Andrew Smith: Yes. I think at the end of the day, the mechanical capability of the rig is still important. But I think what’s becoming a bigger portion, even – maybe even more important is the embedded technologies and, and the people that we have operating them and the processes that we’re operating with. So, it sort of separates, and, and again, it separates kind of across the board, but I do think that it’s a little too easy just to break it down into the mechanical capabilities because that’s maybe not the thing that’s really the differentiator anymore.

Dan Kutz: Yes, sure. All fair enough and, and helpful color. Maybe just on, on the international components of your business. I think I, I caught a comment that you kind of in Drilling Products expect the normal spring breakup headwinds in Canada and then that you see growth across kind of rest of the world. I was hoping you could maybe unpack the rest of world growth comment into maybe what regions you’re, you’re kind of seeing, seeing growth versus yes, just broadly the kind of global activity trends you’re seeing across the rest of world? Thanks.

William Hendricks: Sure. So, outside of the spring break up in Canada, really pleased about the performance in Canada. We were just talking about it at our quarterly business reviews a week ago and, committing the team for how well they’re doing up there. That can be a challenging market, managing the fluctuations there and they’re doing a great job. When we look at the rest of the world outside of North America, our teams are very well-positioned in various countries the growing rig count that we’re going to see in Argentina over the years, and I’m just going to start with Latin America, is going to be beneficial and weighted towards us. We have a facility in Argentina that can do remanufacturing on the drill bits down there and repairs.

And so, we’re well-positioned for activity increase there on our product side. When you look at the Middle East, we’re, our remanufacturing center in Saudi Arabia is being upgraded to a manufacturing center. So, we’ll be able to build some of our drill bit product lines new there. That market is shifting over from a purchase market to a rental market and that’s where we excel in the U.S. We know the rental market very well. We understand that model. Our teams do a great job here in the U.S. and I’m highly confident that they’ll be able to transfer, that process over to Saudi as well. You go to Oman, we have a remanufacturing facility there. And I’ll also add that we’re going to put more focus on North Africa. We’re going to see some longer-term and, not this year, but this is a multi-year, outlook for us.

We’re going to see, more investment in North Africa in terms of natural gas supply to Europe over the next few years. And I think we’ll be well-positioned to take advantage of that as well.

Dan Kutz: Great. All helpful. Thanks a lot. I’ll turn it back.

Andrew Smith: Thanks.

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

Connor Jensen: Hi, guys. Thanks for sneaking me in at the end here.

William Hendricks: Good morning.

Connor Jensen: You called for flat rig guidance for Q2. I saw the website has kind of been trending a little bit above that to start the quarter, but obviously, with oil prices down here, that might have some impact. Do you have any line of sight on rigs that might get idled or let go during the quarter?

William Hendricks: We do have some line of sight on a small number of rigs that could be idled over the next quarter or so, but I would say that overall, we’re going to be relatively steady here in the second quarter. Again at this level of WTI, there could be some slight softening in the market and we could see a little bit of a downward trend on our rig count, but I don’t expect this to be a large downward trend.

Connor Jensen: Got it. That makes sense. And then you highlighted some cost controls in the business over the last couple of quarters, specifically in completions. Wondering if you could expand on what you’re doing there on the cost side and some of the different levers you could pull given different activity scenarios?

William Hendricks: Yes, sure. So, from an operational standpoint in the field, our completions teams are doing a great job. As we work through integration last year, there was still some opportunities to take some more costs out of the system and, and you’ll see that materialize in the numbers relatively speaking, here in the first and second quarters this year. They did a great job getting some cost out in the first quarter, a little bit more in the second quarter. So, on a relative basis, just looking at our cost line, they continue to improve and the team is doing a great job. It’s all supported by the level of technology and, and performance that, that we offer in the field, and that’s what keeps that business relatively steady outside of a little bit of white space that we could see towards the end of this quarter.

Connor Jensen: Great. Thanks. I’ll turn it back.

William Hendricks: Thanks.

Operator: Your next question comes from the line of Jeff LeBlanc from TPH and Co. Please go ahead.

Jeff LeBlanc: Good morning, Andy and team.

William Hendricks: Good morning.

Jeff LeBlanc: Good morning, Andy and team. Thank you for taking my question. I just had one. You mentioned earlier that the majority of your CapEx is directed towards maintenance. Could you quantify the amount of maintenance CapEx for both drilling and completions a little bit more specifically? Thank you.

Andrew Smith: Yes, so, let me – I don’t have it at my fingertips, but I can kind of give you an idea. On the drilling side, probably looking at maintenance CapEx, approaching $175 million or so and then on the completion side, I would say we’re probably, yes, around probably $200 million or so of maintenance CapEx.

Jeff LeBlanc: Okay. And could those numbers trend lower in a more downward scenario or those relatively steady even as oil prices –?

Andrew Smith: Yes, 100%. They are very linear with activity, right. So, as activity falls off, and you’ll see those numbers trend down and in a severe downturn, you see them trend way down. So, certainly we adjust that kind of based on where the market is, but you’re typically going to see it go pretty linear with activity.

Jeff LeBlanc: Okay. Awesome. Thank you for the color. I’ll hand the call back to the operator.

Andrew Smith: Thanks.

Operator: Your next question comes from the line of Don Crist from Johnson Rice. Please go ahead.

Don Crist: Hi, guys. Just one quick one for me. As and it’s more on visibility than anything else. As I understand the business on the drilling side, you pretty much know two pads ahead of time when that rig is going to work. And I don’t know if that’s correct or not in today’s market, but could you translate that into the fresh pumping side for us? I mean, and what I’m driving at is, can the pressure pumping side, within two weeks’ notice start dropping crews? I don’t think that’s the case, but just wanted to know if that was a clarification.

William Hendricks: Hi, Don, good morning. So, as you mentioned in drilling, we said that’s the part of our business usually gets the first call or notification to pick-up a rig or lay down a rig and it’s usually with a fair amount of notice and we’ve got line of sight on that. And so, we can work that into projections. But, I would say even today, completions is, is at that longer-term notice in a lot of cases too because of the quality of the E&Ps that we’re working for, the longer-term programs that they’re working on. We know their plans, further in advance as well. And if there’s going to be any changes, we typically have a fair amount of notice on that as well and can talk about that. So, when we talk about, what we think is going to happen in the upcoming quarter, we can talk with a relative degree of certainty around that outside of macroeconomics and any changes in the commodity.

Don Crist: Okay. I appreciate that color. So, I’ll turn it back. Thanks for everything.

William Hendricks: Thanks, Don.

Andrew Smith: Thanks.

Operator: Your final call comes from the line of Sean Mitchell from Daniel Energy Partners. Please go ahead.

Sean Mitchell: Hi, good morning, guys. Andy, just – you may have mentioned this earlier and I might have missed it, but how much of the completion fleet that is natural gas capable today is actually working in oil basins versus gas basins?

William Hendricks: So, yes, 80% of what we have out there today can burn natural gas. I would say it’s probably, it’s the same kind of split as our overall split, roughly, 70%, 30%. So, we actually have a lot of equipment that burns natural gas working out in the Permian these days just because of the ability to get low-cost natural gas and, and truck it through our own systems. We have two compression stations for CNG and we have well over 100 trucks that can deliver CNG and blend it with fuel gas. So, there’s a huge opportunity for our customers out in West Texas and New Mexico to use natural gas. And so, it’s not just weighted to the gas basins, but we’re using a lot out in the Permian too.

Sean Mitchell: Yes. And look, I know Drilling Products is a little bit smaller, but that segment continues to grow with pretty strong returns. Are there any M&A opportunities there as we kind of head into a softer period here that you guys are thinking about or do you think there’ll be opportunities there?

Andrew Smith: Yes, Sean. Look, I think that the Drilling Products platform is, is great and they do a fantastic job and really, they market their products as well as anyone. And so, I do think there are opportunities to push more through that if we can find something that fits right. We don’t necessarily have anything in mind, but certainly, we see a lot of things and we think about a lot of things all the time and then if we are in a period where those things become one, available, and, two, priced right, certainly, we would look at it and decide whether or not it makes sense for us to pull something in.

William Hendricks: The acquisition of Ulterra was part of a bigger plan to add a segment that was relatively low CapEx compared to everything else we do, and we’re certainly pleased with that performance.

Andrew Smith: Yes, I agree.

Sean Mitchell: All right. Thanks guys.

William Hendricks: Thanks, Sean.

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

William Hendricks: Thanks, Van. Listen, I just want to thank everybody that dialed into the call today, especially our employees. You guys are doing a great job out there. So, thanks for everything everybody does. Appreciate it.

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