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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.
Thank you, operator. Good morning, and welcome to Patterson-UTI's earning 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 takes no obligation to publicly update or revise any forward-looking statements. Statements made in this conference call include non-GAAP financial measures. The required reconciliations to GAAP financial measures are included on our website, patenergy.com and in the company's press release issued prior to this conference call. I will now turn the call over to Andy Hendricks, President, Patterson-UTI's Chief Executive Officer.
Thank you, Mike, and welcome to Patterson-UTI's first quarter conference call. The 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. In 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 oil basins, activity has remained steady, supported by high oil prices. In the near term, customer consolidation is muting the market's response to strong oil prices. This should resolve over time and, at current oil prices, we anticipate some modest demand upside in oil 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 had 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 U.S. will require increased production, with natural gas remaining 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 remains 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 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 1 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-UTI 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 to 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 EcoCell lithium battery technology. Often highline power is accessible but not in adequate quantities to fully power the rig by itself. Our grid assist package can complement 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's 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 NexTier is largely complete, marking a significant milestone for the company. The team's dedication and expertise has been exceptional. The leadership within the group has shown 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 lead. The 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 as the industry is getting more disciplined with capital deployment. We're also excited by what we have seen from our cementing business following the integration of legacy Patterson-UTI and NexTier operations. We have seen 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 by Q3. Our Drilling Products segment continues to perform exceptionally well. Ulterra 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 Ulterra's international business is expected to achieve high teens revenue growth this year, primarily driven by strong performance in the Middle East. Ulterra 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 quarter.
Thanks, Andy. Total reported revenue for the quarter was $1,510,000,000. 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 and $98 million used to repurchase 9 million shares. Annualized, 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 2 quarters since we closed the NexTier merger and the Ulterra 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 we 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 U.S. 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 31, we had term contracts for drilling rigs in the U.S., 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 and an average of 41 rigs operating under term contracts over the 4 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 U.S. 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 U.S. 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 in 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 a mix shift away from 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 relatively steady. As expected, the Haynesville was the largest declining basin during the quarter. Our natural gas-powered equipment continues 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 continued its 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 resume 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 U.S., Drilling Products market share hit a record for the company in the first quarter, and the segment again saw an improvement in revenue per U.S. industry rig 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 noncash charge of $2 million associated with the step-up in asset value of the drill bits that were on the books 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 noncash 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 totaled $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, and 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're turning more of our adjusted EBITDA into 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 8 months since the merger between NexTier and Patterson-UTI 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 is still ample room for improvement in our Completions business, and we are actively pursuing strategies to enhance its performance. We are confident in our abilities to deliver additional value to our shareholders through these efforts. I'll now turn the call back over to Andy Hendricks for closing remarks
Thanks, Andy. As we've discussed, the results for the first quarter of 2024 were strong, and I am 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 U.S. 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 designs. As well, the last year in our industry has demonstrated how the service market in the U.S. 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 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 8 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 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 Tamika, and we'll open the lines for Q&A.
[Operator Instructions] Your first question is from the line of Luke Lemoine with Piper Sandler.
Could you talk a little bit about where you are with your wellsite integration within frac?
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, NexTier, really excited about what they've accomplished over the years, especially with the ability to integrate wireline systems, base oil 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. We'll essentially make sure that everything is working like it needs to be as efficient as possible. Next to that, you have Next Mile Logistics, which is a trucking delivery company of 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 sand, wet sand, whatever is required for those particular jobs. And when you think about how we're doing more simul-frac and sometimes 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. Next on the list would be the power solution systems that we have, where we actually create CNG in the basin. We can deliver CNG to the wellsite. We can blend natural gas, and we can do that and efficiently power the systems at the wellsite. And what that does for us by being able to manage that blending of fuel gas and CNG at the wellsite, we can increase the percent of 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 other companies. After that, you've got the next sub and 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 equipment and maximize the number of stages per week and stages per month that we get. And so we continue to add each of those into the fleets we had at Patterson-UTI pre-merger and worked 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. It's just part of the normal operation these days as we really essentially completed the integration.
Yes. Luke, I would add to that a little bit, talking broader about the synergies and sort of what we said early on. Recall that of the $200 million that we expected to get, we thought that would be about 1/3 supply chain, 1/3 SG&A and 1/3 on the sales sort of integration side, 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 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.
Okay, that's helpful. And then you both talked about the gaps in the dedicated fleets in 2Q. Is this just on natural gas or these oil basins as well? And then you talked about 3Q frac, Andy, being up from 2Q. I realize it's early but could this be above 1Q as well in 3Q? Or between 1Q and 2Q kind of be a good starting point for now?
So we have some white space in the calendar in Q2, where we have actually more than one of our E&P customers that completion 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.
Your next question is from the line of Jim Rollyson with Raymond James.
Andy, there's -- you mentioned this and it's been a pretty popular topic. Obviously, the gas market has 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? I'm just curious, it seems like we're in this short term, people have been focused on the 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.
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 continue 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 E&Ps 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, and that gets into the whole data center discussion. 2025 and going forward, the U.S. 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. It's not apparent that there's enough pipelines coming from the Permian that negates the need for Haynesville gas. So it does seem like that the Haynesville gas is going to be required some time in '25 to start increasing activity and certainly going into '26. And so structurally, 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. It sets it up structurally well for 2025 and beyond.
Yes, that's kind of what I was thinking. And switching gears a little bit, just on the Drilling Services side for your U.S. rig business, costs have obviously trended up over time for a whole host of reasons. But did notice that they actually ticked down for the first time in several quarters this quarter. I'm just curious what the driver was and maybe how you guys are thinking about cost going forward, in part in the second quarter related to the [ 300 ] margin -- daily margin drop, but also just beyond the second quarter.
Yes. Some of it is related to the change in the rig count, and our rig count in first quarter held up better than we thought it would. And so we do think we lose a couple more rigs going into Q2 from where we are today, but 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 if you had a 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.
Your next question is to remind of Scott Gruber with Citigroup.
So staying on the rig side, Andy, if your rig count is flattish from here from that 2Q level, do we expect margins to be flattish as well in 3Q and 4Q?
Yes. I was just looking at 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 and 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 is kind of the bottom for completions for us. But on the rig side, it's probably across Q2, Q3.
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 the gaps in the schedules that will impact 2Q. But just curious, in Texas and on the oil side, has the business been pretty steady for you guys? Or have you guys seen some reduction in activity on that side of the business as well? And if you have, do you see a path to recapture some of that share in the second half?
Yes, in the oil basins, we just remain relatively steady outside of completions, efficiency being higher than we plan and bumping up against the drilling rigs and needing some more inventory. But we've seen it relatively steady in the oil basins. Everybody's talked 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. Structurally, they just kind of get that market back into balance, which is why I think that Q2 is likely the bottom in Completions and then across Q2, Q3 for Drilling. But back to oil, it's just been steady and oil is 80% of what happens in the U.S. market today.
Your next question is from the line of Alexa Petrick with Goldman Sachs.
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?
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 committed to returning at least 50%. This year, we've committed to returning at least $400 million combined between dividends and buybacks. So I don't want to give certainly too much of an expectation as to how exactly we're going to do that. 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. And then going forward, again, I don't want to give too much of an expectation going into 2025. We are still committed to the 50% return. But we'll just have to judge at the time how and we expect to do that.
Yes. The part that's exciting to me is that 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. But this market is in really good shape for us to do that for a multiyear period.
Yes. I mean, touching on what Andy just said, it's 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 an environment.
Okay, 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?
So in general, we've been busy over the last year-plus, and for the last 8 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 it right now and very strong in all those sectors across North America. And we have international growth opportunities with Ulterra drill bits. And so we just think we're in really good shape. So there's -- people have asked at times, "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, relatively small to what we've done in the previous year. 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 continuing the 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.
Your next question is from the line of Derek Podhaizer with Barclays.
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.
Yes, I wouldn't say it's repeatable going forward. This was a legal situation we got into with one of our suppliers that finally settled. We settled it in the quarter and it's a onetime event.
Got it. And then maybe just to go back to Lou's question up at the top of the call 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 it will fall somewhere between 1Q and 2Q?
I actually think we can get back to the first quarter levels because I think what you're going to see from some of our E&P customers over the next year is 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 have seen them increase 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 some of that white space out of the calendar. But I think we'll see some of the E&Ps do that.
Got it, that's helpful. I appreciate that. The last one, just an update around e-frac. Sounds like you put another Emerald out there. I know you're going to be at 140,000 horsepower by midyear. Can you just discuss about are you getting multiyear contracts here? What do the payback looks like? Any early results, indications on that R&M expense, maintenance CapEx? Just help us understand more about the benefits you're seeing out of your e-frac program so far. off, are you buying power or are you leasing power?
So today, we're getting long-term agreements with customers who have multiyear drilling programs. And so that is really well for deployment of the new fleets and the Emerald systems. Really excited about how that deployment has gone. As I mentioned earlier, the startup on those operations has gone really smooth. We are actually buying the equipment in terms of the frac spreads, 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 using CapEx. So you actually see the electric frac spreads fleets in our CapEx budget but we are leasing the power systems.
Your next question is from the line of Arun Jayaram with JPMorgan.
Andy, maybe just a 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, it sounds like, that you're looking at. Maybe you could discuss some of the pros and cons around each of those technologies.
Sure. So we continue to roll out the e-fleets this year, and we will likely continue to roll out e-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 e-fleets. We get agreements for multiyears on multiyear projects with some of the bigger operators. And so there is demand for that. You've got certain operators that say, "Yes, I'd really like to have the e-fleet." 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 100% gas recip engines that are direct drive into pumps. We do that on some jobs. We run Turbidirect drive systems on some jobs as well. In general, we use those to supplement the dual fuel to increase the natural gas consumption and 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. They don't have gas on all pads. 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 4 is still going to be a strong part of the market and a large part of what we do. You'll see us 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 experienced operating all those systems, and we'll take a balanced approach on the new technology.
Great. A quick follow-up. On the E&P side, Andy, we continue to see efficiency gains with E&Ps more regularly touting the ability to 18- to 21-hour 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 daywork? And talk to us on some of the ways you're adapting your contracting structure to take advantage to win in some of these efficiency gains that you're providing at the wellsite?
Yes, I'll start with completions first. We essentially get paid by the stage. So we -- the faster we at 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 flag fleet, 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 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. 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 that we're very competitive. When we're out there bidding on work, we are certainly up there in the top quartile of what we earn on the rigs.
Your next question is from the line of Stephen Gengaro with Stifel.
Two things for me. The first, you mentioned owning the e-fleets. I'm pretty sure next year used to lease at least a couple of those e-fleets. Have you purchased those or are they still on a sort of lease-to-own arrangement?
No. We never leased any e-fleets. We did have some leased equipment. We bought some of that equipment out. We still have some small leases, but we've never leased an e-fleet.
Okay. So I apologize, I thought there was some on that type of arrangement. So from a bigger picture perspective, you mentioned sort of the efficiencies on the frac side and how that has played into maybe a little white space on the calendar. When we think about just kind of the market in the medium term, are efficiency gains 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?
I think what will happen is you'll see an increase in the rig count. I think that operators are seeing companies like ourselves improve efficiencies over the last couple of years. And 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 were in the past as well. And so when you add up multiple wells on a pad and longer laterals than what we've drilled in the past as the completion is bumping up against it.
Your next question is from the line of Saurabh Pant with Bank of America.
Maybe I'll just ask one on the e-fleet side first. Last quarter, and if I remember correctly, you teased us a little bit about 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?
So post merger, I would say that's still pretty new. The teams have been looking at what do we think e-fleets 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 NexTier completions and the teams that have been operating the e-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 experience running thousands of AC induction motors and other systems. And then even on our drilling side, where we have manufactured dissembled drilling rigs with cable management systems and power systems and battery backup systems. And so putting all those teams together puts us in a unique position to take a fresh look at what we think e-frac needs to look like. And so I'd say it's still early days, but I am excited from what I've been hearing from the workshops that the teams have been running. I don't think you'll see anything new from us this year because it does take time to engineer and manufacture. But we'll keep you posted as we work through it.
Okay. No, that's helpful, Andy. And then one, Andy Smith, maybe for you. I know you reiterated that at least 40% EBITDA to free cash flow conversion outlook. Can you give us a little help on the moving pieces within that? Andy, I know you got it to the CapEx number. I'm assuming that's unchanged. Maybe a little bit color on working capital, cash taxes, anything else that we should be mindful of as we think about conversion.
Yes. So working capital, again, will fluctuate throughout the year. Recall, if you recall, in the fourth quarter of last year, we received a relatively large prepayment from one of our customers. That has worked itself off in the first quarter. Now what will happen again, it's a large customer, will rebuild some receivables from that customer over the course of the second quarter. So I would expect that the second quarter is a little lighter than the first quarter, but then we'll kind of get back to the same sort of working capital performance that we had in the first quarter and the third. And then in the fourth quarter, depending upon what they decide to do. Historically, they decided to sort of advance pay in the fourth quarter. We'll see if that comes through this year or not. So that's not really been counted on in terms of our free cash flow conversion, so that would be upside. But I would expect that you'll see it kind of working capital will be a little bit less of a source in the second quarter and then more of a source of cash in the third and fourth quarter.
Okay. Okay, perfect. And anything on cash taxes we should be mindful of, Andy, for this year versus last year?
Cash taxes are negligible. We're planning for somewhere in the neighborhood of $20 million to $30 million this year of cash tax.
Your next question is from the line of Waqar Syed with ATB Capital Markets.
Andy, in terms of active pressure pumping fleets, how has that changed over the last couple of quarters?
Well, it's actually hard to quantify because we've had to take some fleets and put them together to do simul-fracs and fracs. And so the fleet count actually changes on a month-to-month basis internally as we look at the numbers. And so we really try to stay focused more on hydraulic horsepower hours in terms of how we look at the business. And so internally, it becomes less of an interesting number to try to assess how many fleets we have out there and more about how much active horsepower that we have out there. And when we're looking to do calculations on the business, like I said, we're using hydraulic horsepower hours because that takes into account flow rates, pressures, volumes and how much time we're out on location doing things.
So maybe if I ask in a different way. How has the manned horsepower changed in the last couple of quarters? Has it remained relatively similar and all the changes in revenues are more a factor of that horsepower having less utilization? Or is it more that some of the horsepower you've set aside as well because of weaker demand?
Yes. So if you look at across all the horsepower that we're running, there's still strong demand for the electrics. Total horsepower active that we're using has come down a little bit just because of the softening in the market, and also a little bit of softening in pricing that you've seen and not new to anybody in the industry. But I expect that really kind of bottoms in the second quarter, and we see a little bit of an inflection in the third quarter.
Okay. And do you -- could you provide us a color with like what's the mix of e-fleets Tier 4 DGBs and then Tier 2 dual fuel and T2 diesel?
Yes. We have 140,000 horsepower that we'll have of this year. And overall, it's about 80% of our fleet to burn natural gas. So that leaves you with about 20% that are just Tier 2 that don't have the ability to run dual fuel. And as we progress through this year and next year, you'll see that just kind of fade away and drop out. You'll see us, over time, I believe, slowly reduce the amount of horsepower overall just because we just don't need that Tier 2 anymore. And we're going to be disciplined about how we add new technology as we go.
Your next question is from the line of Keith MacKey with RBC Capital Markets.
Just wanted to ask about rig pricing. Specifically, Andy, how are conversations unfolding on the rig side? Certainly, things have been a little bit more stable than they might have been in prior cycles. But rig count has come down and there is quite a bit of impending consolidation, especially in the Permian. Maybe some are looking to use that to get discounts on rigs. So just curious how those conversations are unfolding. And what is your message or your mechanism to maintain an appropriate price or what you view as an appropriate price in this market that's maybe driving some of that stability?
Yes. I think what you see in the market today is when we talk about Tier 1 super-spec rig, that pricing is stable. And so even though some of them may not be working right now just because the changes in the market with consolidation that you're seeing, those rigs will go back to work at some point. As the consolidation process happens, you'll see lower tier rigs drop out of that consolidation process and get replaced back to Tier 1 super-spec. So what we've seen is at the Tier 1 super-spec, that market has remained relatively stable.
Your next question is from the line of John Daniel with Daniel Energy Partners.
Andy, you noted that the market structure is likely to improve. And I think we all believe and hope that activity starts to rebound late this year a little bit but probably a bit more next year. And I'm just wondering if you have that combo of those 2 things, it would seem that things could tighten relatively quickly. So what would your approach be to pricing?
Well, typically, in a very disciplined environment, as activity moves up, pricing moves up. And when you see -- when you look at the Tier 1 super-spec rig market, historically, that's how it's played out is that the demand for those rigs have increased, you've seen increases in pricing along with the activity. And it's interesting how the -- on the completion side, the market has structurally improved over the last few years. And I think there is a bifurcation in the market. And so as the leading technology players find themselves in higher demand, then I think you're going to see those same companies have the ability to move pricing up at the same time as well.
Okay. I mean, I think that as much. I know with the current sort of pressures by some within the E&P industry to sort of eke out concessions and take advantage despite the [ $80 ] oil if there'd be kind of a leading question but maybe a bit more incentive to push pricing a little bit harder.
Yes, I think all of us in the industry have discussed over our last couple of calls, as the natural gas markets have softened, that there's been a softening in pricing there as well. And I think you're hearing from the E&Ps that they've got some concessions. But I really think at this point, especially given our view of where we are and when we think our various service lines are going to bottom out, that you're hearing that concessions have happened. I don't think you're going to hear a lot about concessions going forward. I think that pricing has really stabilized at this point. And with any activity increase in your Tier 1, Tier 2 rig or e-frac or higher-end technology and completions that you're going to have -- you're going to see pricing move up on those.
Okay. And then I know you mentioned in response to 1 question that you'll likely expand e-fleets next year. I'm not looking for you to necessarily quantify that. But given the lead times on various components, have you gone ahead and started placing those orders? And what are they telling you in terms of when you get it?
So we've been working with suppliers. And so we understand their ability to deliver and their ability to meet our needs as we get into next year. And so no real challenges there for us delivering more next year. I would say that our teams are working well with the suppliers and no issue. And it's just -- we've mentioned it before. Now that we're a larger company in terms of completions and with the size and scale that we have with the demand on the new technology, we certainly want to be a part of that. And so we will continue to add electric and other new technologies a little bit of time over in a measured way over the next few years as part of our CapEx budget.
Okay. And then the final one for me, just going back to the comment you made about market structure likely to improve. I'm assuming you were talking about the completions market, but by any chance, were you also that to the drilling space as well?
I appreciate the clarification because I was really leaning more towards completions and completions-related services, not just hydraulic fracturing, but you've got wireline, you've got others. And I think over time, you'll see some of the smaller companies or smaller public market cap companies start to come together, and that will just structurally improve the market over the next year or 2.
At this time, there are no further audio questions. I will now hand the call back over to the presenters for any closing remarks.
Thanks, Tamika. I'd like to thank everybody that dialed into the call today. We're really excited about where we are in the market and our ability to generate strong free cash flow and returning that to shareholders even in a relatively steady market. So thanks a lot.
This concludes today's call. Thank you for joining. You may now disconnect your lines.