Patterson-UTI Energy, Inc. (NASDAQ:PTEN) Q1 2024 Earnings Call Transcript

Patterson-UTI Energy, Inc. (NASDAQ:PTEN) Q1 2024 Earnings Call Transcript May 2, 2024

Patterson-UTI Energy, Inc. isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Ladies and gentlemen, welcome to the Patterson UTI First Quarter 2024 conference call. [Operator Instructions]. As a reminder, today’s call is being recorded. I will now hand today’s call over to Mike Sabella, Vice President of Investor Relations. Please go ahead, sir.

Mike Sabella: Thank you, operator. Good morning and welcome to Patterson-UTI earnings conference call to discuss our first quarter 2024 results with me today are Andy Hendricks, President and Chief Executive Officer; and Andy Smith, Chief Financial Officer. As a reminder, statements that are made in this conference call that refer to the Company’s or management’s plans, intentions, targets, beliefs, expectations or predictions for the future are considered forward looking statements. These forward looking statements are subject to risks and uncertainties as disclosed in the company’s SEC filings, which could cause the Company’s actual results to differ materially. The Company take no obligation to publicly update or revise any forward-looking statements.

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

Andy Hendricks: Thank you, Mike, and welcome to Patterson Thiago First Quarter Conference Call. First quarter unfolded, largely as we anticipated with another quarter of strong free cash flow. The steady environment continued in the oil basins with activity and production relatively consistent with late last year and natural gas basins. Our customers are being impacted by weak natural gas prices, and they are responding by reducing activity as we expected. Against this backdrop, Patterson UTI delivered strong results during the quarter, and we met our guidance in each of our operating segments. The results in the first quarter demonstrate the free cash flow generating capabilities of the Company, even as we invest to maintain our position as a long-term winner in the U.S. shale drilling and completion.

And we expect to continue returning a significant amount of cash to shareholders bifurcation amongst oilfield product and service providers is presenting an opportunity for high-quality companies to generate strong free cash flow even in a slightly softening market. We are investing in technologies that enhance the efficiency of the U.S. shale model, and this should improve the returns and free cash flow profile of our company. Over the long term, our customers are recognizing and rewarding providers that have a differentiated service offering and Patterson-UTI stands amongst the leaders across multiple product and service lines. Differentiation has defined this cycle, and we believe that if we invest in the right technologies and deliver consistent and repeatable top-quality product for our customers.

We will be rewarded with higher activity and utilization, and our results are the best evidence. We delivered another strong quarter in Q1, and both our drilling and completions businesses again outperformed. We expect this outperformance will continue over the long term. On the macro outlook in all basins, activity has remained steady, supported by high oil prices in the near term, customer consolidation is meeting the market’s response to strong oil prices that should resolve over time. And at current oil prices, we anticipate some modest demand upside in all basins starting later this year. Weak natural gas prices are impacting industry activity in the near term so far, activity in natural gas basins has held up better than we’d anticipated, particularly in the Northeast, but we are seeing more natural gas activity reductions continuing in Q2, and we expect natural gas activity is likely to then remain steady with second quarter levels through the rest of the year.

Nevertheless, our long-term positive view on natural gas is unchanged. New LNG exports and growing demand for power in the US will require increased production with natural gas remain a part of the industry growth narrative for 2025 and beyond. In our Drilling segment services in our Drilling Services segment, we had another strong quarter with our rig count, again outperforming the industry. Average pricing on recent term contracts remained stable and margins have been resilient. In the U.S., we started the second quarter operating 118 rigs, and we are currently operating 116 rigs, although we have line of sight for a couple of more rig drops as our customers respond to natural gas prices and as customer consolidation creates some potential reduction in near term activity.

We continue to see very high demand for our Tier one drilling assets, and we believe our rig fleet is positioned to outperform the market with upside, even if the overall market is flat, customer consolidation will create a period of churn, which we are starting to see in the second quarter, but this should be followed by a high-grading process. And that transition is when Patterson GTI. should see the most benefit. We are excited about the way the market is taking shape over the long term. On the technology front, we’re seeing great results from the investments we’ve made to add automation systems to the drilling rig controls over half of our rigs today are running our Cortex operating system and our Cortex key edge devices. Demand is high, and we have allocated a portion of our CapEx to continue adding these systems.

The growing presence of these products on our rigs is enhancing the value of our service offering. We are also advancing the way we power our rigs by beginning to integrate our grid assist package with our E. T cell lithium battery technology, often high-line power accessible, but not an adequate quantities to fully power the rig by itself, our grid assist package can complement the grid grid power to fully power the rig, even when the utility is only providing a fraction of the electricity grid assist has shown the ability to substantially decrease the cost of powering a rig and slash emissions by up to 90% compared to rigs that are still using diesel generators. Our technologies differentiate Patterson-UTI Drilling business and should give our rigs a sustainable advantage over many peers in the industry.

In completion services, we had another strong quarter. The operational integration with next year is largely complete, marking a significant milestone for the Company. The team’s dedication and expertise has been exceptional. The leadership within the group mission skill and commitment through this process, and we extend our sincerest gratitude for everyone’s outstanding efforts. Looking ahead, we remain focused on identifying additional synergies to further enhance our position as well as completion leader benefits so far have been obvious with relatively steady financial performance compared to the pre-merger entities. Even as the market has slowed, this is evidence that the merger is creating value. We have achieved our $200 million annualized synergy target faster than we initially expected.

During this integration process, the team has continued to advance our transition to natural gas powered frac equipment in a capital efficient manner. We deployed our latest round of Emerald electric frac equipment throughout the month of April, with the fleet integrated with our power solutions and going to work in West Texas for a large established customer so far, the results have been fantastic with the equipment averaging over 21 hours per day since it started up a great achievement for a new fleet. We remain on track to grow our electric frac horsepower to 140,000 by the middle of the year. And upon delivery, we still expect that almost 80% of our fleets will be able to be powered by natural gas. We are also field testing other 100% natural gas powered frac technologies, and the flexibility is one of the biggest benefits of not overly relying on one solution.

We think our full suite of natural gas-powered frac assets, including our dual-fuel equipment, is as competitive as any company in the industry. Overall, we expect our nameplate horsepower will continue to decline as we retire older diesel assets. We suspect others are taking a similar approach to retiring older assets is the industry is getting more disciplined with capital deployment. We are also excited by what we have seen from our cementing business following the integration of legacy Patterson ETI. next year. Operations, we are seeing strong market penetration. And as our customers are extending laterals, they are asking for higher quality, cementing equipment leading to bifurcation in this market. Similar to what we are seeing in frac, we believe our cementing business is well-positioned to continue to improve results regarding our customer base, we believe much of the churn has already occurred for this year, and we think the rest of the year should be relatively steady with a steady customer book and a likelihood that frac activity will improve somewhat in Q3.

We think Q2 is likely the low point for our Company this year in terms of frac activity, we’ve had some customer-specific gaps that opened up on our calendar during Q2, and those customers should resume normal activity. Why two three our Drilling Products segment continues to perform exceptionally well. Ultera reached a new company record for revenue generated per industry rig in the U.S., highlighting the strength of our offerings in the domestic market. Internationally, we saw strong growth with revenue abroad of more than 15% compared to the first quarter a year ago. These results highlight the effectiveness of our drilling products and meeting the evolving needs of our global customer base. We remain optimistic about the growth prospects of the Drilling Products segment, even in a flattish U.S. onshore market and Alterra’s international business is expected to achieve high 10s revenue growth this year, primarily driven by strong performance in the Middle East, while Terra also had its first successful run in the North Sea which is a market where the Company has not historically participated.

Early results in that region have been great and we have been awarded other sections of the project. This is a great example of an expansion into a new market. The strategic investments we are making will set us up for profitable growth even in a relatively flat market at the same time we are delivering strong free cash flow and returning a significant amount of cash back to our investors. We consider this balanced capital allocation strategy critical for enhancing shareholder value over the long term, and we are optimistic that we can continue delivering on this approach. I’ll now turn it over to Andy Smith, who will review the financial results for the first four group.

Andy Smith: Thank you, Andy. Total reported revenue for the quarter was $1.510 billion. We reported net income attributable to common shareholders of $51 million or $0.13 per share in the first quarter. This included $12 million in merger and integration expenses. Our adjusted net income attributable to common shareholders, excluding the merger and integration expenses was $61 million or $0.15 per share and assumes a 21% federal statutory tax rate on those charges. Adjusted EBITDA for the quarter totaled $375 million, which also excludes the previously mentioned merger and integration expenses. Our weighted average share count was 408 million shares during Q1, and we exited the quarter with 404 million shares outstanding. Our free cash flow for the first quarter was $139 million.

During the first quarter, we returned $130 million to shareholders, including an $0.08 per share dividend, $98 million used to repurchase 9 million shares. Annualize the amount we returned to shareholders totaled to more than 10% of the market cap at the end of the first quarter. During the first quarter, we generated significant free cash flow and we opportunistically accelerated our share repurchase program given the dislocation between the share price and our view on the intrinsic value of the share of Patterson UTI stock. In just two quarters since we’ve closed the next term merger and Alterra acquisition, we have repurchased 4% of the post-deal shares outstanding. Our Board has declared an $0.08 per share dividend for Q2. For 2024, we still expect to use at least $400 million to pay dividends and repurchase shares, which would exceed our targeted return of more than 50% of free cash flow to shareholders.

In addition to the cash returned to shareholders in the first quarter, we used more than $30 million to pay down capital leases and retired debt as we look to maintain our low leverage and strong capital structure. In our Drilling Services segment, first quarter revenue was $458 million. Drilling Services adjusted gross profit totaled $186 million during the quarter. In US Contract Drilling, we totaled 11,024 operating days. Average rig revenue per day was $35,680, with average rig operating cost per day of $19,510. The average adjusted rig gross profit per day was $16,170, a decrease of less than $200 from the prior quarter. At March 31st, we had term contracts for drilling rigs in the US, providing for approximately $527 million of future dayrate drilling revenue.

Based on contracts currently in place, we expect an average of 70 rigs operating under term contracts during the second quarter of 2024 at an average of 41 rigs operating under term contracts over the four quarters ending March 31, 2025. In our other drilling services businesses other than U.S. contract drilling, which is mostly international Contract Drilling and directional drilling, first quarter revenue was $64 million with an adjusted gross profit of $8 million. For the second quarter, in US Contract Drilling, we expect to average 114 active rigs compared to 121 active rigs in the first quarter with adjusted gross profit per day expected to be down roughly $300 from the first quarter. Aside from US Contract Drilling, we expect other drilling services adjusted gross profit to be down slightly compared to the first quarter.

Reported revenue for the first quarter on our Completion Services segment totaled $945 million with an adjusted gross profit of $199 million. Most of the sequential change in revenue was a function of lower activity and the mix shift away from higher at higher revenue jobs in the Haynesville, with some limited impact from changes in pricing relative to the fourth quarter. We are pleased with our results in Appalachia where activity was rental relatively steady. As expected, the Haynesville was the largest declining Basin during the quarter. Our natural gas-powered equipment continued to be sold out with high demand and a widening operating cost savings compared to diesel equipment. Our completion activity has declined slightly to start the second quarter, mostly in natural gas basins where customers continue to slow activity in response to low natural gas prices.

Additionally, we have a few dedicated fleets that are operating with planned gaps in the schedule. For the second quarter, we expect completion services revenue of approximately $860 million with an adjusted gross profit of around $170 million. We see an improvement in activity in the third quarter as our dedicated and long term customers resumed completion activity after the pads are drilled. First quarter drilling products revenue totaled $90 million, which was up 2% sequentially. Adjusted gross profit was $41 million. In the US , drilling product market share hit a record for the Company in the first quarter and the segment again saw an improvement in revenue per US industry rate as Ulterra continues to perform very well. Internationally, revenue improved sequentially with gains largely coming from our operations in the Middle East.

Direct operating costs included a non-cash charge of $2 million associated with the step-up in asset value of the drill bits that were on the books at the time of the Ulterra trends at the time the Ulterra transaction closed. The same purchase price accounting adjustment, increased reported segment depreciation and amortization by $6 million during the quarter. We expect the impact of these non-cash charges will reduce as we move through 2024 and will likely be negligible thereafter. For the second quarter, we expect Drilling Products results to be roughly in line compared to the first quarter, we see growth internationally, largely offsetting typical seasonality in Canada with the spring breakup. Other revenue totaled $18 million for the quarter with $7 million in adjusted gross profit.

We expect other second quarter revenue and adjusted gross profit to be flat with the first quarter. Reported selling, general and administrative expense in the first quarter was $65 million. For Q2, we expect SG&A expense of $65 million. On a consolidated basis for the first quarter, total depreciation, depletion, amortization and impairment expense of $275 million. For the second quarter, we expect total depreciation, depletion, amortization and impairment expense of approximately $265 million. During Q1, total CapEx was $227 million, including $83 million in drilling services, $123 million in completion services, $16 million in drilling products, and $5 million in other and corporate. For the second quarter, we expect total CapEx of roughly $180 million with most of the sequential reduction coming from a decline in CapEx in the Completion Services segment.

We expect our annual CapEx spend will be $740 million or less. Our focus remains on maintaining flexibility to adapt to market conditions as needed. While we continue to expect to convert at least 40% of our adjusted EBITDA to free cash flow in 2024. We closed Q1 with nothing drawn on our revolving credit facility as well as $170 million of cash on hand. We do not have any senior note maturities until 2028. We expect to generate another quarter of strong free cash flow in the second quarter, although likely slightly below what we saw in the first quarter. We have a long track record of returning substantial cash to our investors since the start of 2022, we have returned more than 80% of our free cash flow to our investors. Over that same time, we have seen a steady improvement in our free cash flow conversion.

Simply put, we are returning more of our adjusted EBITDA to free cash flow than in the past, and we are committed to giving a significant amount of that free cash flow back to shareholders in the eight months since the merger between next year and Patterson ETI. was finalized, our integration efforts have exceeded our most optimistic expectation. The team’s achievements during this relatively short time frame are evident and the Completion Services segment has remained resilient despite challenging market conditions. The operational integration is largely complete, and we have now achieved our goal to realize more than the $200 million in annualized synergies, which we announced at the time of the transaction. We remain committed to identifying additional cost synergies and revenue opportunities.

There’s still ample room for improvement in our completions business, and we are actively pursuing strategies to enhance its performance. We are confident in our ability to deliver additional value to our shareholders through these efforts. I’ll now turn the call back over to Andy Hendricks for closing remarks.

Andy Hendricks: Thanks, Andy. As we discuss the results from the first quarter of 2024 were strong, and I’m still very constructive on our industry for all of 2024. With Patterson UTI positioned to continue to generate strong free cash flow. Oil prices have shown relative stability. And there is no visibility on any substantial or additional supplies of crude entering the market that will change the current commodity price dynamic. The oil basins in the US drive the vast majority of our activity. There continues to be strong demand for technology in today’s market, including more drilling rig control automation, natural gas-fueled frac technology using electric pumps well placement analytics and new drill bit design as well.

The last year in our industry has demonstrated how the service market in the US has become more disciplined, where although we have seen some softness in the gas markets. Overall activity and pricing has held up better than in similar historical years. We believe all of this translates to a better operational environment for our company and a more investable sector for the market. I’d like to thank all of our teams across Patterson, UTI for all their hard work to successfully integrate the companies over the last eight months and achieve the targeted synergies of over $200 million. Patterson UTI remains in a strong position. We continue to focus on high returns, capital-efficient ways to grow our profitability and to return cash to shareholders through our regular dividend and share buybacks.

We still expect that we will return at least $400 million this year through dividends and share repurchases, which in a flat market should mean further growth in our earnings per share and also return on capital through a steady reduction in share count. Finally, I’d like to thank all the hard-working women and men at Patterson-UTI for what they do to responsibly provide energy to the world. With that, I’d like to hand it back to Mika, and we’ll open the lines for Q&A.

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Q&A Session

Operator: [Operator Instructions]. Your first question is from the line of Luke Lemoine with Piper Sandler.

Luke Lemoine: Good morning. Andy, could you talk a little bit about where you are with your well site integration within frac of?

Andy Hendricks: Yes. So one of the premises of the merger and certainly one of the big synergy buckets is the integration of services that are vertical to us on what was essentially the frac fleets that we had at Patterson-UTI before the merger. So just to remind everybody next year, really excited about what they’ve accomplished over the years, especially with the ability to integrate wireline systems, cased-hole, Wireline and Perforating. And the real benefit to that is you don’t have, as I said before, a $50 million frac-spread waiting on $1 million wireline truck will essentially make sure that everything’s working like it needs to be as efficient as possible. And next to that, you have next mileage logistics, which is a trucking delivery company of the substantial size, which make sure that our frac fleets are never waiting on sand that we always have the sand we need delivered to the pads when we need it both dry and wet sand, whatever is required for those particular jobs.

And when you think about how we’re doing more simul-frac and sometimes trying to frac, those are very large volumes of sand that have to be delivered and you never want to be able to hold up operations hold up the number of stages per day. And the next on the list would be the net the power solution systems that we have, where we actually create CNG in the basin. We can deliver CNG to the well site. We can blend natural gas and we can do that and efficiently power the systems at the well site and what that does for us by being able to manage that blending of fuel gas and CNG at the well site, we can increase the percent substitution so we can reduce fuel costs for customers in the field. We can also reduce emissions by burning more natural gas So in general, we believe that we get higher substitutions because we have this capability than than other companies after that, you’ve got the mix of the real-time systems and we’re monitoring equipment.

We’re monitoring the status of equipment. We’re trying to do predictive analysis on when we need to make changes in the field just to maximize the uptime on the on the equipment and maximize the number of stages per week and stages per month that we get. And so we continue to at each of those into the fleet, we had a Patterson UTI premerger and work through all that. I would say it’s still an ongoing process and we’ll work through it for the rest of the year. But we had several wins early on last year and continue to roll it out just part of the normal operation these days as we really essentially completed the integration.

Andy Smith: Yeah, hey, Luke. I would add to that a little bit I’m talking broader about the synergies and sort of what we said early on you. Our recall that of the $200 million that we expect to begin, we thought that would be about a third supply chain, a third SG&A and a third on the sales sort of integration side of wellsite integration side, I would say that we’ve overachieved in supply chain probably hit our number pretty close on SG&A and are probably a little bit under on the on the wellsite integration, but that’s largely due to market backdrop. So we’ve got additional opportunity there as we go forward as market conditions improve, I think we’ve got more opportunity to really increase the amount we get out of that.

Luke Lemoine: Okay. That’s helpful. And then you’ve both talked about the gaps in the dedicated fleets in 2Q, just on natural gas or these oil basins as well. And then you talked about 3Q frac it being up from 2Q on. I realize it’s early, but could this be above 1Q as well in 3Q or well between 1Q and 2Q kind of a good starting point for now?

Andy Hendricks: So we have we have some white space in the calendar in Q2 where we have actually more than one of our E&P customers that completions it has been running so efficient that we’re bumping up against the drilling rig. And so in discussions with the teams, it looks like we’ll have more inventory in place in Q3. So we’re just we’re in a situation where we’re bumping up the drilling rigs in Q2.And then in Q3, we’ll have steadier work out of those same frac fleets. Operator Your next question is from the line of Jim Rollyson with Raymond James.

Jim Rollyson: Andy, there’s you mentioned this and it’s been a pretty popular topic. Obviously, the gas market’s been pretty soft here of late, but the setup going into next year and probably for the next few years seems to be gaining traction, both on the LNG front and the kind of data center driven electricity implications for gas demand. Have you guys put any pencil to paper just to think about what you believe the impact will be on both frac and drilling activity as we roll into 25 and beyond on how much activity do we need to actually produce the volumes that are required based on where some of the demand estimates are just curious, it seems like we’re in this short term, people have been focused on this soft market condition. But as we go into next year, it seems like this is going to rapidly change and tighten up markets, especially on the gas side, which tightens the overall thing. But just kind of curious, your big picture view as we roll into next year.

Andy Hendricks: Yes. So we’ve got natural gas production along the Gulf Coast and feeding into Henry Hub. And then, of course, we have all the associated gas coming in from the Permian. These days this year, we were supposed to get another Bcf in the pipelines coming out of the Permian competing against gas essentially in the Haynesville, which is why we’ve seen the Haynesville continues to stay soft. We don’t today have visibility on any increase in natural gas for the end of 24. We do have some natural gas customers that have been talking to us about adding a rig or increasing activity to start to plan for things in 2025. I think we’re all just trying to understand right now, what does it look like in terms of more pipeline capacity coming from the Permian and how does that compete against Haynesville gas?

Interestingly enough, I was talking to one of our customers the other day and we were discussing takeaway from the Permian. Some of the EMPs actually have natural gas takeaway over to California at the same time. So not all the associated gas is coming from the Permian to the Gulf Coast and hitting Henry Hub. And California is still going to have strong demand for utilities with natural gas that gets into the whole data center discussion of 2025 and going forward, the US is going to be exporting more LNG. There’s contracts in place for the new plants coming online, especially on the Texas Gulf Coast. The Texas Gulf Coast is going to require more natural gas, and it’s not apparent that there’s enough pipelines coming from the Permian. It negates the need for Haynesville gas So it does seem like that the Haynesville gas is going to be required sometime in 25 to start increasing activity and certainly going into 26 and so structurally and I’m bullish for what’s happening with LNG exports with the increasing need for data centers in the U.S. with natural gas going over to California from the Permian so that it’s not all competing in the Gulf Coast area and it sets it up structurally well for 2025 and beyond.

Jim Rollyson: Yes, that’s kind of what I was thinking. And switching gears a little bit just on the drilling services side for your US rig business costs have obviously trended up over time for a whole host of reasons, but I did notice that they actually ticked down for the first time in several quarters this quarter. Just curious what the driver was and maybe how you guys are thinking about costs going forward in part in the second quarter related to the 300 margin daily margin drop, but also just beyond the second quarter?

Andy Hendricks: Yes. Some of it’s related to the change in the rig count in our rig count in Q1 held up better than we thought it would. And so we do think we lose a couple of more rigs going into Q2 from where we are today, but not a not a big change. So I think you are going to see our costs because of the changes in the rig count on a quarter-to-quarter basis, kind of moving up and down, but essentially they’re still relatively flat yet or flat rig count. We will see maintenance CapEx moderate as activity moderates and then maintenance CapEx come back up as activity comes back up as well. So all in all, we think we’re in line there and still producing strong free cash flow.

Operator: Your next question is from the line of Scott Gruber with Citigroup.

Scott Gruber: Yes, good morning. All right sustain on the rig side. And if your rig count is flattish from here from that 2Q level, we expect margins to be flattish as well in 3Q and 4Q?

Andy Hendricks: Yes, I was just looking at it to projections again. And what we’re seeing is, like I said, we’re going to have a couple of more rigs coming down in Q2. And I think that margins in rig count are likely to bottom somewhere in that Q2, Q3 time frame this year, whereas it’s a little bit different on the completion side. As I mentioned earlier, completions had a different circumstance where we’re going to see their activity bump up a little bit in Q3 with less white space. So Q2’s kind of volume for completions for us. But on the rig side, it’s probably across Q2, Q3.

Scott Gruber: Got you. And then on the completion side, obviously, the gas side of the business is weak today, hopefully bottoming out. And obviously you highlighted that the gaps in the schedule that will impact 2Q. But just curious, you know, in Texas and on the oil side, has the business been been pretty steady for you guys or have you guys seen some reduction in activity on that side of the business as well?

Andy Hendricks: And if you have if you see a path to recapture some of that share in the second half, DAG oil bases, we just remain relatively steady outside of completions, efficiency being higher than we planned and bumping up against the drilling rigs and needing some more inventory. But we see it relatively steady in the oil basins. Everybody talks about the decreases in gas in the Haynesville. We’re going to see the Northeast moderate a little bit, but I believe that’s transitory as structurally. They just kind of get that market back into balance, which is why I think that Q2 is likely to bottom and completions and the cross Q-to-Q free for for drilling. But back to oil, it’s just been steady. Oil is 80% of what happens in the US market today.

Operator: Your next question is from the line of Alexa Petrick with Goldman Sachs.

Alexa Petrick: Hey, good morning, team. I wanted to touch on capital returns briefly, how should we be thinking about the cadence of share repurchases through 2024? And then is this level of capital returns, something we should view as standard going forward when we think about free cash flow payout?

Andy Smith: Yes, in terms of the cadence of how we intend to sort of buy back stock, I don’t want to forecast too much. Obviously, I mean, we’re we’re committed to returning at least 50% this year. We’re committed to returning at least $400 million combined between dividends and buybacks. But I don’t want to give too much of an expectation as to how exactly we’re going to do that will we’ll remain opportunistic as best we can, but still stay within those sort of parameters and those commitment levels that we’ve given you. I think going forward, again, I don’t want to give too much of an expectation going into 2025. We are still committed to the 15% return, but we’ll just have to judge at the time how and we expect to do that.

Andy Hendricks: And the part that’s exciting to me is that, you know, with the structural changes in the oil market that we’ve seen over the last few years and the increased level of discipline that we’ve seen in oilfield services we’re just in a really good position to generate strong free cash flow and return cash to shareholders. And so we’re still confident in our ability to commit to returning at least $ 400 million this year through dividends and buybacks. And what we said, as Andy mentioned, is we want to give at least 50% of our free cash flow back to shareholders for this market and really good shape for us to do that for a multiyear period.

Andy Smith: And then touching on what ending assignments a bit of a unique situation for us right now because we’re generating in what we think is a pretty good amount of free cash flow. At the same time, our stock price is just not where we would expect it to be given the operational backdrop that we have. And so we think it’s a great opportunity to buy back shares in this type of environment.

Alexa Petrick: That’s very helpful. And then on M&A. Briefly, you’ve been historically very acquisitive. How are you thinking about M&A just with all this industry consolidation picking up? And then do you think there’s any incremental opportunities for technology-focused M&A.

Andy Hendricks: So in general, we’ve been busy over the last year plus and for the last eight months, focused on integration and still working on some integration. We’re really happy with the structure of the Company that we have right now. We cover a lot of the sector between contract drilling, directional drilling, drill bits, completions, wireline, cementing, natural gas power systems I mean, you name it. We’re covering right now and very strong in all those sectors across North America. And we have international growth opportunities with Altera drill bits. And so we just think we’re in really good shape. So there’s people have asked the time, hey, is there anything more that you believe that you need in the company? And the answer is no, we have everything we need right now.

We have done acquisitions in the technology space in the past, a relatively small to what we’ve done in the previous year. Would there may be opportunities to do that going forward. We’ll just have to wait and see, but we’re really focused on just running what we have today and continued integration continuing to capture synergies. I do think there’s room for more consolidation in the sector. And I think there probably will be companies that you see that come together, especially when you get into the companies that are smaller market caps than we are. I think you’ll see that some of those companies find opportunities to pull themselves together and create new entities. And that’s going to be very positive structurally for the market. As I mentioned earlier, I’m upbeat about the structure of the market today, and I actually only think it improves going forward.

Operator: Your next question is from the line of Derek Podhaizer with Barclays.

Derek Podhaizer: Hey, guys. Wanted to ask about that $10 million gain that we saw in completion services. Maybe if you could expand on what that is and if it’s repeatable going forward?

Andy Smith: Yes, I wouldn’t say it’s repeatable going forward. This was a legal situation we got into with one of our suppliers have been finally settled. We settled in the quarter and it’s a one-time thing.

Derek Podhaizer: Got it. And then maybe just to go back to Lou’s question up at the top of the call, I’m asking about where completion services can go from a gross profit perspective. Just the fact that you have fleets going back to work utilization picking up in the third quarter? Can we get back to first quarter levels or OB fall somewhere between 1 and 2Q?

Andy Hendricks: I actually think we’ll get back to the first quarter lows because I think what you’re going to see from some of our E&P customers over the next year, they’re looking at how much improvement they’ve been getting in frac efficiency and now how they’re short on inventory. And so you actually may see an increase in drilling capacity by adding a rig here or there just so that they can keep inventory in front of the frac spread, and that’s what we need to be able to do that. It just takes them that white space out of the calendar. But I think we’ll see some of the E & P’s do that time.

Derek Podhaizer: That’s helpful. Appreciate that. On the last one, yes, just an update around e-frac. Sounds like you put another ammo fleet out there and they’re going to be at one 40,000 horsepower by midyear. Can you just discuss about are you get multi-year contracts here? And what are the payback looks like any early results, indications on that. R&D expense, maintenance CapEx? Just help us understand more about the benefits you’re seeing out of your e-frac program so far? And also, are you buying power or are you leasing power?

Andy Hendricks: So today, we’re getting long-term agreements with customers who have multi-year drilling programs. And so that served us really well for deployment of the new fleet and the Emerald systems really excited about how that deployment is gone. As I mentioned earlier, the start-up on those operations has gone really smooth. We are actually buying the equipment in terms of the frac spread, unlike others who are probably out there, leasing equipment, but we are leasing the power because the power gets used in different ways where we feel it’s in our best interest to own the actual frac equipment and actually buy it with using CapEx. So you actually see the electric frac spreads fleet’s in our CapEx budget, but we are leasing the power system.

Operator: Your next question is from the line of Arun Jayaram with JPMorgan.

Arun Jayaram: Yes, good morning, Andy. Maybe just to follow up, you guys have always taken a pragmatic approach regarding fleet renewal. And I was wondering if you could maybe comment on thoughts on incremental E fleet deployments versus the 100% gas technology sounds like that you’re looking at maybe you can discuss some of the pros and cons around each of those technologies.

Andy Hendricks: Sure. We continue to rollout the fleets this year, and we will likely continue to rollout out fleets over the next few years as well as part of our CapEx budget and retire older equipment at the same time, there is demand for the fleets. We get agreements for multi-years on multiyear projects and some of the bigger operators. And so, you know, there is demand for that you’ve got certain operators and say, I’d really like to have the easily and it’s part of our competency that we have in the Company. And we like the way they run but we also, at the same time don’t want to be tied to a single solution in terms of new technology. And so we are running some one-offs in gas recip engines that are direct drive into pumps.

We do that on some jobs. We run turbine Direct Drive Systems on some jobs as well. In general, we use those to supplement the dual fuel to increase the natural gas consumption and debt substitution on some of those jobs. But clients still like the flexibility out there with the dual fuel, we still have some customers that have gas on some pads, but they don’t have gas on all pad. And in some cases, distances for CNG trucking don’t necessarily make sense. And so I think you’re going to see multiple solutions. It’s Tier four DGB. It’s still going to be a strong part of the market and a large part of what we do. You’ll see to continue to add electric spreads tied to 100% natural gas generators. And then you’ll see us add other newer technologies, whether it be gas, recip direct drive to the pumps or turbines direct drive to the pumps for various reasons, depending on what makes sense in the basin for different customers.

But we have experience operating all those systems and we’ll take a balanced approach on the new technology.

Arun Jayaram: Okay. Thanks, Andy. A quick follow up on the E & P side, Andy, we continue to see efficiency gains with E & P’s. We’re regularly touting the ability to have 18 to 21 tower pumping hours per day, pretty remarkable achievements. And on the drilling side, we continue to see a lot of efficiency gains, faster cycle times. I was wondering, given this dynamic customers are working your equipment harder and harder, are you shifting your philosophy on performance based contracts from day work and talk to us on some of the ways you’re adapting your contracting structure to take advantage to win and in some of these efficiency gains that you’re providing at the wellsite?

Andy Hendricks: Yes, our completions are here we essentially get paid by the day. And so we the faster we get the stages out there per week per month. The better that is in terms of capital efficiency for us. So that’s certainly a win. And on the Power Solutions, as we continue to integrate power solutions onto our frac fleets, we can play in the arbitrage on the natural gas prices and generate additional revenue around there and we get part of that fuel savings. On the drilling side, we do have some performance-based contracts in place. We also continue to work with operators for various other things. There’s the technology additions that are happening on the rigs as well. And so we do believe that we continue to push up revenue per day through the addition of technology.

You know, one of the things to consider is when you’re looking across all the companies, you’re really apples and oranges because different companies report different services in that revenue per day. And so when we report revenue per day for our contract drilling business, we’re giving you the revenue per day for the contract drilling rigs without other services blended in, but we do believe are very competitive when we’re out there bidding on work. And we are certainly up there in the top quartile of what we earn on the rigs say.

Operator: Your next question is from the line of Stephen Gengaro with Stifel.

Stephen Gengaro: Thanks. Good morning, everybody. Two things from me. The first you mentioned owning the fleets. I am pretty sure. Next you’re used to used to lease at least a couple of those. If we have you have you purchased those, are they still on on on a total lease to own arrangement.

Andy Smith: No, we never leased any new fleets. We did have some leased equipment. We bought some of that equipment. Now. We still have some small leases. So there are at least an equally.

Stephen Gengaro: Okay. So I apologize. I thought there were some I’m on that type of arrangements. And so from a bigger picture perspective, you mentioned sort of the efficiencies at the on the frac side and how that as planned, maybe a little white space on the calendar when we think about just kind of the market in the medium term and our efficiency gains on the on the completion side outpacing the rig side at this point. And does that impact sort of the way we should think about the number of completion crews necessary relative to the rig count.

Andy Hendricks: I think what will happen is you’ll see an increase in the rig count. I think the operators are seeing companies like ourselves, improve efficiencies over the last couple of years and you know what they were planning in terms of inventory, we’re catching up on that. And so I think like I mentioned earlier, you’ll see a few that may add rigs. And part of that is because we’re drilling longer laterals. And so we’re on the locations a little bit longer with the rigs than we weren’t in the past as well. And so when you add up multiple wells on a pad at longer laterals than what we’ve drilled in the past that into completion, it’s bumping up against.

Operator: Your next question is from the line of Saurabh Pant with Bank of America.

Saurabh Pant: Hi, good morning, Andy, maybe I’ll just ask one on the fleet side first or last quarter. And if I remember correctly, you teased us a little bit about the some technologies you are developing in-house. Can you give us a little update on that? What are you doing? If you can talk to that and what should we expect over the next couple of years from in-house development standpoint.

Andy Hendricks: So, you know, post merger, I would say that’s still pretty new. The teams have been looking at it. You know, what do we think a fleet should look like going forward and in the future. And when I say the teams, I’m talking about the experience we have in our next year completions and the teams that have been operating the fleets that we’ve been running plus our teams within our current power Electrical Engineering division that have actually built some of the control systems and variable frequency drive houses for E. fleets in the past and do that for our drilling systems and have experienced here running thousands of AC induction motors and other systems. And then even on our drilling side, where we have we have manufactured assembled drilling rigs.