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Date
Thursday, April 23, 2026 at 10 a.m. ET
Call participants
- President & Chief Executive Officer — William Andrew Hendricks
- Executive Vice President & Chief Financial Officer — C. Andrew Smith
Takeaways
- Total revenue -- $1.12 billion reported for the quarter, reflecting the combined performance of all segments.
- Net loss -- $25 million, equivalent to $0.06 per share, attributed to common shareholders for the quarter.
- Adjusted EBITDA -- $205 million, which included $3 million in early contract termination revenue from Drilling Services.
- Drilling Services revenue -- $352 million, with adjusted gross profit of $134 million, inclusive of early termination payments.
- Drilling operating rig count -- Averaged 92 rigs with 8,301 operating days during the period.
- Completion Services revenue -- $680 million reported, with adjusted gross profit at $98 million, including a $9 million estimated EBITDA impact from a five-day winter storm disruption.
- Drilling Products revenue -- $80 million with adjusted gross profit of $33 million, noting revenue headwinds from Middle East conflict and tungsten price inflation.
- Guidance—rig reactivation -- Second-quarter guidance targets an average drilling rig count of about 90, with an anticipated exit between 92 and 95 rigs; reactivation and mobilization costs for these rigs are estimated at $5 million (as operating expenses).
- Guidance—adjusted gross profit -- Expected in the second quarter at $130 million for Drilling Services, $105 million for Completion Services, and a slight decline for Drilling Products due to lower international profitability and seasonal factors.
- CapEx -- $117 million in total, split among Drilling Services ($54 million), Completion Services ($45 million), Drilling Products ($16 million), and Corporate/Other ($1 million).
- Cash position -- $337 million in cash, nothing drawn on the $500 million revolving credit facility; no senior note maturities until 2028.
- Quarterly dividend -- $0.10 per share declared, payable June 15 to shareholders of record as of June 1.
- Frac fleet utilization -- Nearly full calendar for active assets; natural gas-powered fleets are "essentially sold out" and running near full utilization.
- Technology & equipment investment -- Continued shift toward 100% natural gas-powered Emerald completions fleet, with plans for over 15% of active horsepower to be fully gas-powered by year-end and approximately 90% at least partially gas-powered.
- Pricing trends—drilling -- "Pricing that is starting to move up from the low $30 thousands at the leading edge" for drilling rigs, with customer willingness to provide term contracts for technology upgrades.
- Pricing trends—completions -- Evidence of 10% price increases already received from some customers, with management expecting pricing to move up "steadily over the next months through the end of the year."
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Risks
- Middle East conflict -- "The conflict in the Middle East has increased risk in one of our key regions, which contributes roughly 10% to 15% of segment revenue, primarily from Saudi Arabia. Land activity in Saudi Arabia largely tracked expectations.
- Input cost inflation -- "meaningful inflation in several key inputs, particularly the material tungsten, where prices are significantly higher than a year ago. In addition, our.
- Winter storm disruption -- Completion Services "effectively paused the completions business for five days" in January, causing a $9 million estimated EBITDA impact.
Summary
Patterson-UTI Energy (PTEN +2.57%) reported higher-than-anticipated completion demand and tightening frac market conditions, with natural gas-powered equipment operating near full capacity and calendars now essentially filled into the third quarter. Management signaled a disciplined approach to rig and fleet reactivation by prioritizing pricing and return improvements ahead of capacity additions, reinforced by specific accounts of customer willingness to accept higher contract dayrates and term contracts for technology upgrades. Despite international headwinds from geopolitical conflict and material inflation, the company expects to deploy more rigs over the year, with a visible line of sight to sustainable free cash flow, a stable balance sheet, and continued returns to shareholders.
- Customer conversations reveal preparations for rig reactivation and increased completion activity later in the quarter, as current oil prices surpass assumptions built into initial budgets.
- Full calendar utilization is resulting in mix-and-duration contract pricing, ranging from spot work to six-month or longer pricing reopeners, providing flexibility to capture near-term pricing upside.
- Capital allocation remains centered on new technology—such as the Emerald fleet and Apex XC+ upgrades—rather than reactivating older, less efficient equipment, with reactivation of cold-stacked horsepower requiring investments beyond $10 million per fleet yet delivering uncertain long-term returns.
- On a segment level, the Drilling Products business grew to record market share in several key international markets, despite lower adjusted gross profit sequentially due to external disruptions and cost pressures.
Industry glossary
- Frac calendar: Scheduling system for allocating hydraulic fracturing fleet resources to customer projects, reflecting asset utilization and market tightness.
- Cold-stacked horsepower: Pressure-pumping equipment that is temporarily idled and not maintained for immediate reactivation, often representing older or less efficient assets.
- DUC inventory: "Drilled but Uncompleted" well inventory; wells that have been drilled but await completion services such as hydraulic fracturing.
- Emerald fleet: Patterson-UTI's proprietary fleet of 100% natural gas-powered hydraulic fracturing pumps, marketed as a next-generation completion technology.
- Apex XC+: Patterson-UTI's advanced, highly upgraded drilling rig platform designed for deeper and more technically demanding well operations.
Full Conference Call Transcript
William Andrew Hendricks: Thank you, Mike. Welcome to our first quarter earnings conference call. I am going to begin by saying we are hiring. Now let us get started. The 2026 built on our momentum from 2025 with strong field execution supported by our technology and digital offerings across our diversified drilling and completions businesses. Our team stayed focused on the same priorities that drove last year's results—staying close to customers, delivering high-quality services and products that help them operate efficiently, and aligning CapEx and operating costs with the opportunities ahead. We are proud of our performance and believe our position across all our businesses will allow us to continue delivering strong cash returns across a range of market conditions.
The commodity outlook has shifted materially since the start of the year due to heightened geopolitical risk and oil supply disruptions in the Middle East, which will likely reshape global oil supply and demand balances for several years. These developments underscore the strategic importance of U.S. oil and natural gas production and reinforce the need for a diversified global energy supply base, with U.S. shale production more critical than ever. Over the past several years, even as expectations for U.S. shale activity have fluctuated, we have remained focused on operational excellence in our core businesses. We have consistently believed that excelling in our core operating businesses is critical to enhancing shareholder value regardless of the macro environment.
Today, we are pleased with the efficiency of our operations, and as U.S. shale activity inflects higher, we believe the decisions we have made position us to capture outsized value from a higher U.S. rig count. As a predominantly shale services company, we will always evaluate opportunities to deploy capital and expand our exposure to other geographies and product lines. However, we will remain disciplined and focused on returns for any potential growth investment. Momentum appears to be shifting back toward U.S. land activity over the coming quarters, but our corporate priorities remain unchanged.
We will continue investing in technology and equipment that differentiates our services and supports long-term free cash flow per share while maintaining capital discipline, balance sheet strength, and consistent returns of capital to shareholders. We are well positioned to execute on these priorities. From a macro perspective, the outlook is improving, though the pace of recovery remains somewhat difficult to predict. We believe the industry will need to increase drilling and completion activity just to maintain oil production. With oil prices now running significantly above the mid-December levels assumed in many customers' 2026 budgets, we are encouraged by the setup for higher U.S. drilling and completion demand.
Some customers have already started to make plans for higher activity levels later this quarter, and we increasingly hear that the strip is likely to incentivize additional incremental oil-directed drilling and completion activity in 2026 at approximately $70 and, if those prices hold, higher activity into 2027 becomes more likely. As is typical, private customers are moving faster than the publics. Natural gas activity also appears likely to improve as newly commissioned LNG facilities drive higher export volumes. While some of the incremental demand may be met by additional pipeline capacity from the Permian Basin later in 2026, we believe additional drilling and completion activity in gas-focused basins will be needed to fully supply that growth.
As a result, we believe natural gas-directed drilling and completion activity is likely to increase in 2027. In our Drilling Services segment, we are very pleased with how the first quarter unfolded. Pricing remained steady, reflecting the value customers place on performance and reliability. In addition, the cost control programs we implemented towards the end of last year continued to gain traction and provided meaningful support to results. Because customer programs typically adjust with a lag to changes in commodity prices, activity for some customers in the first half of the year continues to reflect prior budget assumptions. We are seeing conditions improve, and we expect momentum to build through the quarter.
We expect our rig count will exit the second quarter above the quarterly average and near the high point so far for the year, around 92 to 95 rigs depending on the timing, positioning us well as we move into the second half. As E&Ps continue to drill deeper zones and extend lateral lengths, the importance of rig capability and contractor performance continues to grow. The number of the most capable rigs—those with the load-bearing capacity and pipe handling systems required for today's deeper and longer, more complex wells—remains limited and driven by investments from the best performing drilling contractors.
With our in-house engineering expertise and disciplined approach to upgrades, we believe we are well positioned to gain share in this growing market in a capital-efficient manner. As rigs become larger and more technical, we expect this to strengthen our competitive position and support higher returns over time. Our Completion Services segment delivered solid results for the quarter despite disruption from a January winter storm that effectively paused the completions business for five days. Excluding that impact, our frac operations ran near capacity with our natural gas-powered assets near fully utilized.
Demand for completion services is improving, particularly in 2026, and we are in discussions with customers on higher pricing to more appropriately reflect rising demand and the high industry utilization. Available frac capacity across the industry is limited, and the few fleets that could be reactivated are among the industry's oldest and least efficient. At current pricing, reactivation does not seem economical, and pricing would need to rise meaningfully to incentivize incremental supply as demand increases. While our completions business has nearly 250 thousand cold-stacked horsepower that could technically be reactivated, we have been clear that our priority is to invest in newer technologies that will drive long-term returns.
Our cold-stacked equipment represents the oldest diesel equipment in our fleet, and reactivating a single fleet would require more than $10 million investment. While the equipment could likely find work in the current market, the long-term return potential remains uncertain, and we are not prioritizing investment in these older assets. Over the past several years, we have high-graded our fleet by investing in newer natural gas-powered technologies that we believe will remain in demand and generate strong returns for years to come. We continue to expect our nameplate horsepower to decline this year as we execute this high-grading strategy. Over the past several years, the frac industry has seen consolidation and bifurcation of equipment quality and efficiency.
Lower-tier pricing has constrained cash generation for smaller peers, limiting their access to capital and slowing investment in new technology. This dynamic continues to widen the gap between industry leaders and the broader peer group, supporting a more rational and stable market with structurally higher returns over time. We expect our nameplate horsepower to continue to decline as we direct capital toward expanding our Emerald fleet of 100% natural gas-powered assets. By year-end, we expect more than 15% of our active horsepower to be powered entirely by natural gas, with approximately 90% powered at least partially by natural gas.
We believe we have one of the highest quality fleets in the industry, and this transition reflects our ongoing focus on improving operational performance. In our Drilling Products segment, the team delivered solid performance despite several industry headwinds. The conflict in the Middle East has increased risk in one of our key regions, which contributes roughly 10% to 15% of segment revenue, primarily from Saudi Arabia. Land activity in Saudi Arabia largely tracked expectations during the quarter, although activity in certain regions was impacted. On the cost side, we have experienced meaningful inflation in several key inputs, particularly the material tungsten, where prices are significantly higher than a year ago.
In addition, our Middle East operations have seen higher logistics and personnel costs due to the ongoing conflict in the region. Even with these challenges, our drilling products business delivered only a modest decline in adjusted gross profit versus the fourth quarter, and we are actively pursuing additional actions to further mitigate these risks. From a competitive standpoint, we are encouraged by our position. We are pleased with the team's performance, and we believe we have grown to record market share in several key markets, including Saudi Arabia. In the U.S., we also believe there is additional upside with several large customers.
Overall, our teams executed at a high level in the first quarter, maintaining a disciplined focus on service differentiation, capital allocation, and cost control as we navigated a demand environment shaped by customer budgets built on a crude oil price deck well below the current strip. We believe the indicators increasingly point to a period of higher commodity prices. Based on our customer conversations, we expect this to drive an increase in U.S. shale activity starting later in the second quarter and continuing into the second half of the year. Even if oil prices moderate somewhat from current levels, we would still expect upside versus today's activity.
As we approach an inflection in U.S. activity, it is worth briefly reflecting on the strategy we have followed the past few years. While we continue to evaluate opportunities to expand beyond our core markets, our priority will always be return-on-capital driven, and we have yet to find compelling opportunities that have cleared our investment threshold. We remain focused on strengthening our competitive position in our core businesses and improving efficiency, operationally and financially. As we have always said, we believe disciplined capital allocation and continuous improvement in our existing businesses are important ways to enhance shareholder value. With activity now inflecting higher, the decisions we have made the past several years position us to deliver improved performance going forward.
We are pleased with where the company stands today and are confident in our ability to continue delivering strong cash returns to shareholders. I will now turn it over to C. Andrew Smith, who will review the financial results for the quarter.
C. Andrew Smith: Thanks, Andy. Total reported revenue for the quarter was $1.117 billion. We reported a net loss attributable to common shareholders of $25 million, or $0.06 per share. Adjusted EBITDA for the quarter totaled $205 million, which included $3 million in early contract termination revenue in the Drilling Services segment. Our weighted average share count was 380 million shares during Q1. As expected, seasonal working capital headwinds impacted free cash flow in the first quarter. Given the timing and variability of these items throughout the year, we view full-year free cash flow as the most meaningful measure of performance, with working capital turning into a tailwind in the second half.
In our Drilling Services segment, first quarter revenue was $352 million and adjusted gross profit was $134 million. Revenue and adjusted gross profit included the previously mentioned $3 million of early contract termination payments. In U.S. contract drilling, we totaled 8,301 operating days in the quarter, with an average operating rig count of 92 rigs. Excluding early termination revenue, pricing was relatively steady versus the fourth quarter, and we continue to see benefits from the cost reduction actions implemented late last year. For the second quarter in Drilling Services, we expect our rig count to average around 90 rigs, and we expect to exit the quarter above the average as we reactivate rigs in the back half of the quarter.
We expect adjusted gross profit in the Drilling Services segment to be approximately $130 million. Our guidance includes $5 million of rig reactivation and mobilization costs and assumes minimal second quarter revenue contribution from those reactivations. In our Completion Services segment, first quarter revenue was $680 million, and adjusted gross profit was $98 million. Results reflected the impact of roughly five days of winter storm disruption in January. Excluding that disruption, our frac calendars were essentially full with limited spare capacity to increase activity and an extremely efficient calendar. For the second quarter, we expect Completion Services adjusted gross profit to be approximately $105 million with near full utilization of our active assets.
First quarter Drilling Products revenue was $80 million and adjusted gross profit was $33 million. Results reflected disruption in the Middle East related to the ongoing conflict and some cost inflation. For the second quarter, we expect Drilling Products adjusted gross profit to decline slightly, driven by lower profitability in our international business, particularly in the Middle East, and the normal impact of spring breakup in Canada. Other revenue was $6 million for the quarter, with adjusted gross profit of $3 million. For the second quarter, we expect Other adjusted gross profit to be approximately $5 million. General and administrative expenses in the first quarter were $69 million. For the second quarter, we expect G&A to be approximately $67 million.
On a consolidated basis in the first quarter, depreciation, depletion, amortization and impairment expense totaled $218 million. For the second quarter, we expect it to be approximately $220 million. During the first quarter, total CapEx was $117 million, including $54 million in Drilling Services, $45 million in Completion Services, $16 million in Drilling Products, and $1 million in Other and Corporate. We ended the first quarter with $337 million of cash on hand and nothing drawn on our $500 million revolving credit facility. We have no senior note maturities until 2028. Our board has approved a quarterly dividend of $0.10 per share, payable June 15 to shareholders of record as of June 1.
I will now turn it back to William Andrew Hendricks for closing remarks.
William Andrew Hendricks: Thanks, Andy. I want to close the prepared remarks with some additional comments on our company and the industry. The commodity outlook has shifted meaningfully since the start of the year, with both current and future oil prices now well above the assumptions embedded in our customers' initial 2026 budgets. While many customers remain cautious in the near term, we are seeing a clear change in market tone, including more discussions around rig reactivations, stronger completion demand, and improving pricing across our businesses. Taken together, we have much more clarity on the market direction, and these dynamics point to a more constructive environment for activity and profitability for Patterson-UTI Energy, Inc.
Even as we expect industry drilling and completion activity to inflect higher, we will continue to invest in our strategic initiatives to improve returns. In completions, we will continue to favor technology investments over overinvesting in our older cold-stacked equipment, and we will invest at a measured pace into new assets that should generate stronger returns over multiple years. In drilling, we are executing a disciplined cadence of structural upgrades to support deeper wells and longer laterals, consistent with where customer demand is trending. Digital and AI investments remain central to our strategy and are embedded across all of our operations.
With the changing market sentiment, we believe that technology upgrades will be well supported through favorable contractual structures to support accretive returns. Finally, while the macro environment has changed, our corporate priorities have not. We remain focused on generating durable returns and sustainable free cash flow through the cycle while returning capital to shareholders. Our balance sheet remains strong, and we expect to deliver another solid year of free cash flow in 2026. As we evaluate opportunities to deploy capital, we will remain disciplined and prioritize investments that offer the highest return potential. With that, I would like to thank the men and women of Patterson-UTI Energy, Inc., who work hard every day to help provide energy to the world.
Abby, could you please open the lines for questions?
Operator: We will now open the call for questions. If you have dialed in and would like to ask a question, please press star then 1 on your telephone keypad. If you are called upon to ask your question and are listening via speakerphone on your device, please pick up your handset and ensure that your phone is not on mute when asking your question. To be able to take as many questions as possible, we ask that you please limit yourself to one question and one follow-up. Our first question comes from the line of Saurabh Pant with Bank of America. Your line is open.
Saurabh Pant: Hi. Good morning, Andy and Andy. Andy, I think your inbox is going to be full of résumés by the end of the day after listening to your opening statement. It sounds like the initial leg of the upside is being driven by the private completion side, which makes sense. Already, we are talking about Patterson-UTI Energy, Inc. saying you are pretty much sold out on the high-end fleet, and several peers have said the same. How are the publics thinking about when and how much they want to add activity, if they want to add activity? At that stage, what would the supply side of the equation look like?
How much capacity would we have or not have on the sidelines ready to come back, maybe both on the rig and the frac side?
William Andrew Hendricks: Okay. Let me see where I can start. To begin with, we are really excited about the opportunity to put drilling rigs back to work, and like I mentioned earlier, we think we will be somewhere between 92 to 95 rigs as we exit the quarter based on timing. That is going to lead to higher completions demand over time. The interesting challenge that we have in the industry is we are sold out of our top-tier equipment. We are essentially sold out of everything that can burn natural gas, and we certainly will see a demand for more capacity as we move through the year.
Before we start adding more capacity, we are going to be very focused on returns, trying to improve pricing where we can. We will continue the discussions that we are already having with a number of our customers on what that pricing should look like given the tightness in the market and given the demand. You will see instances over time of trading of customers within the market. We are going to work on improving pricing and improving returns before we start adding capacity. I think that is critically important, especially given how pricing in completions has been pushed down over the last couple of years.
It is important for us and for our shareholders to improve returns where we can before we start bringing more capacity onto the market on the completion side.
Saurabh Pant: That makes a ton of sense, Andy. On the way pricing would work—on the rig side, there is a contract book. How would contract duration look? How quickly can we expect higher pricing to show up in your numbers based on your contract book? And on the frac side, how should we think about pricing reopeners—three months, six months—or are there still a sufficient number of annual contracts where pricing would take time to reset?
William Andrew Hendricks: I think the best way I can describe the pricing situation on the rig side is that when we did the last quarterly conference call, we said leading edge was in the low $30 thousands per day, down from the mid- to low-$30 thousands. What we are seeing today is pricing that is starting to move up from the low $30 thousands. I am not ready to call mid- to low-$30 thousands, but it is definitely moving up from the low $30 thousands at the leading edge with everything fully loaded on the drilling rig, and we are excited about that.
As we get requests for technology upgrades on the drilling rigs—structural or digital—that leads to an investment and is going to require a term contract, and we are hearing favorable commentary from our customers that they are willing to do that as well. That will lock in those returns for the investments that we have to make. On the frac side, we are in discussions with customers today. We have anecdotal evidence where some customers have already given us 10% pricing increases.
That is relatively small compared to how completions pricing has been pushed down over the last couple of years, but given the tightness in the market—from our side and what we hear from competitors—pricing will move up steadily over the next months through the end of the year.
Saurabh Pant: Just to clarify, are the majority of your frac contracts on three- to six-month pricing reopeners?
William Andrew Hendricks: It is a mix. We have some spot work in the second quarter. We have some longer-term contracts where pricing only resets every six months for some very large customers. We also have some customers where you revisit it as frequently as every month. So we have a mix.
Derek John Podhaizer: Hey, good morning. Maybe a first question on the rig supply. I think on the website you are at 88 rigs today. You are talking about adding up to seven rigs by the end of the quarter. How material are the expenses to get those rigs back to work? And how many more rigs would you have behind that will require real capital investments and the upgrades you are talking about for deeper wells and longer laterals? I am thinking through putting upward pressure on that low-$30 thousands dayrate toward the mid-$30 thousands or even into the mid- to high-$30 thousands like we saw last cycle.
On a rig-by-rig basis, what would the required capital cost be to bring certain rigs back after these seven or ten?
William Andrew Hendricks: For the rigs that are going back to work, it has not been too long since they were working, but there are some costs incurred to put them back to work. From an accounting standpoint, we also have to capitalize some of the mobilizations, and we have some rigs that are moving in different parts of the country. That puts us at around $5 million in OpEx to get everything back to work and put a number of rigs out through the end of the second quarter and into the third. We also get revenue back from that—we get paid for mobilizations—but it flows through operating expense, not CapEx.
As we move forward through the year for some of the structural upgrades, we think we have a relatively low cost for a number of our customers. It could be in the range of just a few million dollars, and we can see paybacks in a year to a year and a half on some of that, depending on the dayrates, and we will lock that into term contracts. That will start to push dayrates higher. When we get into the large structural upgrades, the CapEx costs are significantly higher.
For the Apex XC+ rig we have working in the field today—which went through a large upgrade process—those dayrates are pushing $40 thousand a day, and in the market we are in, we expect to be exceeding $40 thousand a day toward the end of this year and early next year with those types of large structural upgrades.
Derek John Podhaizer: Thanks. On the frac side, you are effectively sold out. It is going to take a lot to bring equipment off the fence given it is legacy diesel. Can you talk to the white space in the calendar in Q2? Has that been fully soaked up? How is the second half firming up for your current frac equipment? What needs to happen on the current active fleet as far as white space being soaked up for the remainder of the calendar year before you would consider adding incremental new builds, likely next-gen 100% natural gas type of equipment?
William Andrew Hendricks: This has been a very dynamic situation. As of last week, there was some white space in the calendar that a lot of people might not have expected given commodity prices. As of two days ago, we have basically filled the majority of that white space. Hats off to the team in completions for working with customers to fill that up. For completions, the second quarter is really a transitory quarter—not quite the inflection we are seeing in drilling—but that inflection in completions comes right after that. We feel that as of today we are fully loaded in the third quarter.
I am really pleased with what the team is doing, how they are working with customers, and how they have loaded up the calendar, especially considering how the overall U.S. rig count had continued to come down earlier in the year.
James Rollyson: Good morning. Andy, as you look at this inflection, you have talked about how tight the underlying frac market is. How do you think about getting all your pricing back to where you were two to three years ago? Given what you have been doing on the cost side over the last couple of years, how does that translate into margins relative to, say, the low-20s EBITDA margins in Completion Services right after the Nextier close? Just trying to connect the dots on where margins might trend over the next couple of years.
William Andrew Hendricks: What is important for us right now is to constructively work with our customer base to get pricing back in line with where we are in the market. We have been pushed down in completions pricing for the last couple of years, and for shareholders, we need to get returns back to a reasonable level. While we are still generating good cash flow, there is an opportunity to get returns higher, and we want to do that before we start adding capacity. At the same time, throughout this year, we have been adding the new Emerald pumps that are 100% natural gas-burning. We are really excited about the uptake in the market.
These pumps are essentially spoken for with various customers even before they show up in our inventory. It has been a measured pace to bring those out, and when we do, it improves our pricing and returns as we introduce those into various fleets. We do not want to add significant capacity to the market until we can structurally move pricing back to where we think it needs to be to get our returns. Positively, a number of our competitors are near sold out too. With consolidation in the completions market over the last five years, it is structurally in a better place.
While we are all still competitive, there is a measured level of discipline to improve returns for shareholders before adding capacity.
C. Andrew Smith: On CapEx, we set a budget at the beginning of the year implying a down year as we were all expecting. Conditions today look remarkably different than during our budget cycle. We are looking at places where there could be opportunity to lean into what we think is going to be a pretty strong price environment, but we do not have an updated figure to provide today.
Scott Andrew Gruber: Good morning. Staying on frac pricing, the fleet is much more stratified today. To set an upside scenario, how much incremental pricing would you need to see on direct drive and e-frac to support new builds that reflect fleet expansion and not just replacement?
William Andrew Hendricks: When we look at how we are deploying the new Emerald direct drive—100% natural gas—into our existing fleet, the economics are very good, and the way we are pricing those is very good. The bigger need is to lift the average across the equipment that has been under contract over the last year or so. We need to get our overall average up. It is not really about what we are getting for the new technology; that is working well and generating the returns we want. I am more concerned about lifting overall averages. We are entering a very tight market for completions.
We have been sold out of everything that can burn natural gas for a few quarters, and overall the industry is about to enter a very tight market for completions. That bodes well for all of us trying to get returns up to acceptable levels, and then we can look at capacity increases of new technology.
C. Andrew Smith: Given where we are in the market and the premium gas-burning equipment gets today, we are seeing pricing improvement across the fleet—more so on the gas-burning equipment. With increasing visibility over the next couple of years, you do not have to see a huge amount of pricing to justify some new builds into this type of market, but you probably still need 5% to 10% additional.
Scott Andrew Gruber: On the gap between Emerald kit and dual fuel—there is likely a gap between Emerald and Tier 4 dual, and a gap between Tier 4 and Tier 2 dual. As pricing improves, do those gaps compress or does everything move up while spreads sustain or widen due to diesel displacement economics?
William Andrew Hendricks: You are correct—there are various levels of technology and pricing differentials between them. The market we are about to go into over the next six months is a rising tide that lifts all boats. The differentiation and pricing differentials will remain, but overall pricing for all levels of technology should move up.
C. Andrew Smith: With the diesel-gas spread, while all pricing will move up, you may see the spread between different levels of equipment widen in terms of cost differentials.
Stephen David Gengaro: Thank you, and good morning. On pricing contracts, given your positive commentary, would you expect a strong inflection point in margins in the third quarter for completions, or more of a smoother increase over a couple of quarters? How should we think about when we see it on the income statement?
William Andrew Hendricks: I think it will be more of a smoother increase in pricing not just over the next two quarters, but into 2027 as well. This will be based on constructive negotiations with our customers. We are going to have customers who want to increase their capacity, and E&Ps we are not working for today may call, creating opportunities and negotiations across the base. We need to do the right thing for shareholders and improve returns, and it is a steady process over multiple quarters.
Stephen David Gengaro: On the drilling side and performance-based packaging of products between completions and drilling, how does that play out in a tighter market? Does it give you more opportunity?
William Andrew Hendricks: We have seen challenges since we introduced our P10 Advantage offering as the market was getting softer. Recently, I have been in discussions with some mid-tier operators who may kick off a program and want to discuss what we can do for them. For a mid-tier operator expanding their program, they may not have all the internal resources. If we can help them on efficiencies across drilling and completions, that is positive. A tighter market should be positive for expanding that offering, and we are well positioned to help.
Arun Jayaram: Good morning, Andy and team. Your prepared comments suggest the rig count is trending up five to seven rigs in Q2. Which U.S. shale basins are you seeing the incremental demand on the rig side?
William Andrew Hendricks: We are seeing it across multiple basins, not concentrated in any one. We have customers in multiple basins looking at their economics—both oil and gas—so it is broad. That is encouraging and suggests further opportunities over the next few quarters to expand the rig count.
Arun Jayaram: You closed your prepared remarks talking about evaluating opportunities to deploy capital. You talked about Emerald technology—100% natural gas. What are you looking for to add incremental capacity? Your nameplate is going down this year, but what market signals are you looking for to deploy growth capital?
William Andrew Hendricks: We have been holding back some cash looking for opportunities to deploy—through increasing the dividend, buying back shares, and looking at M&A. As the market improves, we now have further options because with increasing activity and demand for technology—whether on the completion side with Emerald or on the drilling side with the Apex XC+ rig—we have to evaluate returns and what is the right answer for shareholders as we deploy more capital.
Keith MacKey: Good morning. It is rare to be talking about termination revenue and reactivation in the same call. Can you walk us through those factors? Is it a timing issue on the termination? And with the rig reactivations, what type of CapEx or OpEx do these rigs need to come back? Is it a matter of increasing specification requests by operators?
William Andrew Hendricks: This quarter has had a lot of moving parts. We have had E&P customers that started the year with budgets based on certain commodity prices and pressure from investors to keep CapEx in line. We did have rigs come down and termination payments, in the same quarter we are now discussing putting rigs back to work. That creates challenges as the rig count comes down and then goes back up, with rigs moving between basins. In terms of costs to put rigs back to work after they have come down, if they have been working in the last year, we are probably in the range of $2 million in CapEx if upgrades are required.
There are no upgrades that are less than $1 million for technology—structural or digital—depending on the customer, location, and objectives. That potentially drives more capital spend. As we spend those dollars on upgrades, we certainly want a term contract to cover that.
C. Andrew Smith: To clarify, the rigs we are talking about in the second quarter include $5 million of operating expenses to reactivate those rigs. That is OpEx, not CapEx. The CapEx would be on rigs further out that have not worked as recently and may need structural upgrades.
Keith MacKey: Understood. On inflation, what are you watching and how much can you mitigate?
William Andrew Hendricks: Diesel prices are moving up. On sand, there is plenty in the Permian Basin; we are not seeing challenges there. In smaller basins, things may be starting to tighten, but we expect that to change over time. On the Drilling Products side, tungsten prices are moving up significantly, but we have ways to mitigate that—using more steel body bits versus matrix to reduce tungsten use. If there are costs moving up that we need to pass through, this is the right market to do that, and we will be looking at that as well.
Douglas Lee Becker: Thank you. How many rigs will be reactivated with the $5 million in costs? Is there line of sight to term work, or is the spot market picking up enough to deploy that capital?
William Andrew Hendricks: I would say right now, nothing at that level yet in terms of new long-term awards, but we are looking ahead to the second half of this year and into early 2027 and having those discussions with customers. The $5 million also includes mobilization costs, not just work on the rigs. The market is moving in the right direction to allow potentially significant technology upgrades and possibly taking share. We are excited about the discussions and the changing conditions.
C. Andrew Smith: To clarify, that $5 million ties to the 92 to 95 rig exit rate we were talking about earlier.
Douglas Lee Becker: Understood. Housekeeping: you mentioned the winter storm cost about five days on Completion Services. Any EBITDA impact from that?
C. Andrew Smith: Yes, it was about $9 million. We had that included in our guidance when we gave it last quarter. We were not as precise then—we said $5 million to $10 million—but it ended up at the high end of that range.
Edward Kim: Hi, good morning. I am surprised the overall U.S. land rig count is still roughly flat since the beginning of the Iran conflict about two months ago, even as oil prices have increased substantially. Does that reflect customers being in wait-and-see mode before increasing activity, or is it the lag between making that decision and actually standing up a rig? It does seem based on your outlook that the industry-wide rig count should start picking up within weeks.
C. Andrew Smith: Our customers—just like we did—went through a budget cycle, and a lot of this came on right after plans for the year were made. Changing those plans quickly without surety on where it would end up or how long it would last would be difficult. I am not surprised by the pace at which rigs are starting to come back.
William Andrew Hendricks: In the public data, some of the biggest E&P operators have not changed their programs—they are sticking to budgets this year. I think that will probably stay that way for many of them. You will see other publics and privates move quicker, and that is what you are seeing in our rig count projections. The large E&Ps will relook at budgets for 2027, which is encouraging for next year.
Edward Kim: Based on your commentary, 2026 could almost look like a mirror image of 2025. At the beginning of last year, you were running about 105 active rigs. Is 105 achievable by the fourth quarter of this year, or would that be too much of a stretch?
William Andrew Hendricks: It is too early to project exactly what our rig count number will be at the end of this year, but we are encouraged that we will put more rigs out in the second half after the second quarter. We are happy to be working in this type of market versus what we dealt with last year.
Daniel Robert Kutz: Hey, thanks. Good morning. On the international businesses—looking past the near-term disruptions related to the conflict—have you had any customer conversations outside the Middle East, or even with customers there, that indicate potential activity upside for Patterson-UTI Energy, Inc.'s services and equipment? Any inbound across global Drilling Products, the LatAm drilling footprint, or the Turnwell JV in the UAE?
William Andrew Hendricks: In the Middle East—from Kuwait down to Oman—we have a solid Drilling Products business. Onshore activity was relatively steady, especially in Saudi Arabia and the UAE, but offshore activity shut down midway through the conflict, which had an effect. In Saudi Arabia, our customer was working through inventory in their warehouses, which slowed product sales for everyone. At some point that will end, and product sales should move up. We are seeing higher logistics costs to get products and materials into the Middle East and a slowdown in Kuwait as well. In South America, we shipped two drilling rigs to Argentina.
Over the next one to two years, we expect rig count in Argentina to continue moving up; we may get to participate more—too early to call that yet, but we are in a number of conversations. In Venezuela, there are a number of interested parties looking to increase production, especially in the Orinoco Belt with heavy oil. Those discussions will take time and likely go very slow, but interest is there.
Daniel Robert Kutz: Back to the U.S., some indicate DUC inventories are materially low, which can influence the relative pace of drilling versus completions. Do you track this, and how might it influence the pace between drilling and completions?
William Andrew Hendricks: DUC inventory has come down, directly related to the rig count coming down and the number of wells between drilling and completions. Some smaller customers started the year drilling wells and planned to complete them later; based on current economics, some have called us to frac sooner, and where we could, we accommodated them, which led to better returns on some of that work. It is not widespread yet. Now we are entering a period where the drilling rig count is going to start to move up, and we are going to see DUC inventory start to move up until completion activity moves up.
With the tightness in the completion market, there could be a period where DUCs increase more than normal until more completion capacity is available. That should be very positive for completions in the second half of this year.
Donald Crist: Good morning, guys. Thanks for fitting me in. A macro question: we are hearing that worldwide supplies are dwindling and there is a significant dichotomy between the physical and financial markets for oil. We are hearing the strip could increase materially, and maybe we do not go back to $65 to $70 oil. What is your macro view on oil over the coming years?
William Andrew Hendricks: I am not a commodities trader, but there are interesting things happening. On refined products like jet fuel, kerosene, and distillates, those commodities have been ramping up at a faster rate than crude. Commodity traders on the crude side are watching how products trade to determine what the real cost per barrel should be, given a disconnect between traders’ opinions of where oil should trade versus where you can physically get oil today and where you can move it. We still have a bottleneck of crude in terms of global production that is missing, and that will have to get filled or start moving again, which will take months to work out.
Where the strip trades today looking forward seems more like a best guess versus the material price of a barrel of oil. It will be interesting to see how that shakes out over the next year. I am encouraged by how our customer base is reacting and discussing the forward strip, and by the fact that we can tell you today that we are putting drilling rigs out.
John Matthew Daniel: Thanks for including me. I completely flubbed and thought your call started at ten. Apologies. Three questions—first, from a supply chain perspective for drilling capital equipment, where are the longest lead times today, and could that delay rig reactivations over the next several quarters?
William Andrew Hendricks: There are some long lead items—some close to a year—for specialty items for very large upgrades. We have already been placing orders for some long lead items to keep things moving within the existing budget. Our capital budget includes technology upgrades, not just maintenance, so we try to stay in front of long lead items. Lead times are what they are, and we keep items on order where it makes sense. There are shorter lead items as well—structural steel, for example—that we can get in a reasonable timeframe. I have not heard anything from the teams that gives me concern about getting the items we need at the pace we think we will need them.
John Matthew Daniel: You touched on international—Argentina and Venezuela. How do the rig specs differ between those markets and what you are doing in the U.S.? Any operational color?
William Andrew Hendricks: For Argentina (Vaca Muerta), you can take a U.S. rig and move it down there to drill the horizontals—almost identical rig specs. In Venezuela, it depends on the basin. In the Orinoco heavy oil, we were drilling those wells twenty years ago with 1 thousand horsepower rigs. A 1.5 thousand horsepower U.S. rig can work very well there today. There are deeper onshore plays where you would need 2 thousand to 3 thousand horsepower, but I suspect the focus in Venezuela will be on heavy oil, given Gulf Coast refineries, and U.S. rigs can work there.
John Matthew Daniel: For your employees in the Middle East, what percent left when the conflict started and what percent have returned? How do you think about sending more people back?
William Andrew Hendricks: Hats off to our enterprise response team. They ran a 24-hour operation to check on everyone from Kuwait to Oman, ensure people were okay, and assist moves where needed. A bigger concern was rotators working in the field in the UAE—we moved them over land to Oman and then flew them out once flights were operating. At this point, we have everybody back to where they are, and it is relatively business as usual. We still have concerns, but our people there are comfortable working there. If they are not, we certainly have work for them here—we are hiring.
Operator: That concludes our question and answer session. I will now turn the conference back over to William Andrew Hendricks for closing remarks.
William Andrew Hendricks: Thanks, Abby. I just want to thank everybody that dialed in today for our conference call. It is an exciting time in the industry where we are seeing this inflection. We are very happy to report a quarter where we are putting drilling rigs back to work and have a good line of sight on completions for the rest of the year to be relatively fully loaded out. Thank you.
Operator: Ladies and gentlemen, this concludes today's call, and we thank you for your participation. You may now disconnect.
