Patterson-UTI Energy Inc (PTEN) 2022 Q3 法說會逐字稿

Good morning. My name is Dennis, and I will be your conference operator today. At this time, I would like to welcome everyone to the Patterson-UTI Energy Third Quarter 2022 Earnings Conference Call. (Operator Instructions)

I would now like to turn the conference over to Mike Drickamer, Vice President, Investor Relations. Please go ahead.

Thank you, Dennis. Good morning, and on behalf of Patterson-UTI Energy, I'd like to welcome you to today's conference call to discuss the results for the 3 months ended September 30, 2022. Participating in today's call will be Andy Hendricks, Chief Executive Officer; and Andy Smith, Chief Financial Officer.

A quick reminder that statements made in this conference call that state the company's or management's plans, intentions, beliefs, expectations or predictions for the future are 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 undertakes no obligation to publicly update or revise any forward-looking statement.

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.

And now it's my pleasure to turn the call over to Andy Hendricks for some opening remarks. Andy?

Thanks, Mike. Good morning, and thank you for joining us today for Patterson-UTI's third quarter conference call. I'm very pleased with our third quarter results as we continue to deliver growing profitability. We remain focused on generating returns on our invested capital while maintaining the high level of service quality and technology enhancements that customers expect from Patterson-UTI. As our profitability continues to improve, we are increasing our forecast for 2022 consolidated adjusted EBITDA to more than $650 million, up from $600 million. We are also increasing our 2022 CapEx forecast to approximately $425 million, up from the previous $390 million. The increase includes the acceleration of rig upgrades for delivery in 2023, where this CapEx is being largely funded by customers. We also had an opportunistic purchase of an additional Tier 4 pressure pumping horsepower in order to continue to upgrade the quality and earnings power of our fleet.

Looking forward, we remain encouraged by our outlook and our potential to deliver free cash flow. We believe the industry is in the early stages of a multiyear up-cycle given the capital discipline and moderated growth of E&Ps, which are tempering production increases in the U.S. We believe drilling activity continues to increase through next year, thereby driving increases in completion activity. There's been a lot of discussion and reports in the industry over the last few months regarding what E&Ps may or may not do with their drilling plans in the fourth quarter and next year.

As part of our 2023 planning process, we recently completed a survey of a large representative sample of our customers across each of our major businesses to better understand their drilling plans. I believe you will find the results enlightening. Our broad customer base represents a diverse cross-section of the U.S. drilling and completions market, ranging from the largest super-majors to public independents to small private operators. Interestingly, the more than 70 customers we recently spoke with and who primarily drill and complete horizontal wells, plan to add an additional 40 drilling rigs in the fourth quarter and almost 50 rigs in 2023. We believe this is a good cross-section of E&Ps working in the U.S. and an indication of the activity strength in the U.S. market. And while there's been a lot of discussion about what private E&Ps will and won't do, the ones we spoke with plan to add a total of almost 20 rigs in the fourth quarter of 2022 and another 20 rigs in 2023.

And interestingly enough, the increase by private E&Ps is led by those backed by private equity. In summary, based on recent commodity prices, most of the customers we had discussions with expect to add rigs through next year with no real discernible differences among the different classes of operators.

So turning now to my review of operations. First, again, I'm very proud of the solid execution at each of our businesses as we successfully increased both activity and pricing this quarter while continuing to provide excellent customer service. In contract drilling, our average U.S. rig count for the third quarter increased by 7 rigs to 128 rigs. As of today, we have 131 active drilling rigs in the U.S. along with 2 additional rigs that are committed to return to work before the end of the year and 4 that are already contracted to be activated next year. Across the industry, pricing continues to grow as rig demand remains strong. Supply continues to be limited due to the dwindling availability of Tier 1 super-spec drilling rigs combined with the overall tight labor market and challenged supply chain. Leading-edge pricing for these rigs is approximately $40,000 per day, including all ancillary services.

At Patterson-UTI, we are taking advantage of the current strength in pricing by increasing the number of rigs under term contract, thereby improving our earnings visibility and reducing our earnings volatility. During the third quarter, our U.S. contract drilling backlog increased by 61% to $710 million as we signed 27 term contracts, including 3-year contracts for 5 rigs with a major operator.

Our drilling business continues to have a leadership position in reduced emissions technologies, where our EcoCell lithium battery hybrid solution combined with our automated engine management system, has eliminated almost 700,000 gallons of diesel consumption from drilling operations in the first 3 quarters of this year.

In the area of automation, our Cortex operating system continues to be deployed in our drilling operations, which enables the functionality of key applications for improved drilling performance on our APEX rigs.

In pressure pumping, we saw consistent and repeatable execution across the various functions in our pressure pumping business from marketing to operations execution and support functions as well. I would like to commend our team for what has been achieved. We have increased our organizational efficiency and scaled the business with a focus on reducing the overall cost structure. The benefits of this strategy were apparent in the third quarter where we achieved historically high adjusted EBITDA per spread. Additionally, we've been financially disciplined in terms of pressure pumping investments, which when combined with the strong cash flow generation from this business, is driving very favorable financial returns.

We recently completed the opportunistic purchase of 35,000 frac horsepower with Tier 4 engines. These pumps were previously used for lower-pressure pump-down work and will allow us to upgrade existing spreads as well as to possibly activate a 13 frac spread in 2023. Additionally, our pressure pumping business continues to invest in specific technologies to improve our services, such as a new digital platform that will enhance field operations, and our new EcoStart technology to further reduce emissions at the well site.

In directional drilling, we remain focused on technology with many new developments to improve wellbore placement and quality. With regards to the downhole tools used by our teams to steer the wells, we continue to benefit from the vertical integration of engineering key components for our performance drilling Mpact motors and also our Mpower measurements and data transmission systems. This approach has improved our ability to drill wells faster and with better consistency and also to have better control of our costs and supply chain.

Additionally, our well placement data analytics business, Superior QC, continues to lead the industry in improving horizontal well placement accuracy and quality, utilizing proprietary survey correction algorithms. A recent third-party validation process showed that Superior QC's data analytics calculations are approximately 3x more accurate than standard industry algorithms for well placement, allowing for greater precision in the placement of the horizontal section of our customers' wells.

With that, I will now turn the call over to Andy Smith, who will review the financial results for the third quarter.

Thanks, and good morning. As Andy said, we are pleased with our third quarter results where we again achieved improved revenues and margins across all of our segments. Net income for the third quarter was $61.5 million or $0.28 per share, up from $21.9 million or $0.10 per share in the second quarter. In contract drilling, revenues and margins increased significantly in the third quarter due to continued day rate pricing momentum, contract renewals and increasing activity. In the U.S., our average adjusted rig margin per day increased by $1,080 from the second quarter to $10,470. Average rig revenue per day increased by $2,770 as day rates continue to strengthen and we benefit from contract renewals with more favorable pricing. Average rig operating cost per day increased by $1,690 during the third quarter due to general inflationary pressures, including wage increases for both rig-based and support personnel as well as general cost inflation for repairs and maintenance.

At September 30, 2022, we had term contracts for drilling rigs in the U.S., providing for approximately $710 million of future day rate drilling revenue, up from approximately $440 million at the end of the second quarter. Based on contracts currently in place in the U.S., we expect an average of 81 rigs operating under term contracts during the fourth quarter and an average of 56 rigs operating under term contracts over the 4 quarters ending September 30, 2023.

In Colombia, third quarter contract drilling revenues were $18.7 million and adjusted gross margin was $5.8 million. For the fourth quarter, we expect our average rig count in the U.S. to increase by 4 rigs to 132 rigs. Average adjusted rig margin per day is expected to increase approximately $1,500 to almost $12,000 per day, driven by an increase in average rig revenue per day. In Colombia, we expect a seasonal slowdown in the fourth quarter. As such, we expect to generate approximately $12.7 million of contract drilling revenue in Colombia with adjusted gross margin of approximately $3.7 million.

In pressure pumping, revenues and margins improved during the third quarter as our active spreads were highly utilized, and we obtained better customer pricing. Pressure pumping revenues increased 21% sequentially to $288 million, and adjusted gross margin increased 62% sequentially to $76 million. For the fourth quarter, we expect higher downtime due to the holidays. As such, pressure pumping revenue is expected to decrease to $270 million and adjusted gross margin is expected to be $62 million. We then expect revenues and margins to rebound in the first quarter.

In directional drilling during the third quarter, increased pricing and activity resulted in sequentially higher revenues and margins. Directional drilling revenues improved to $58.9 million and adjusted gross margin improved to $10.4 million. For the fourth quarter, we expect incremental pricing gains with activity levels slightly higher than the third quarter. As such, we see fourth quarter revenue improving to $61 million and adjusted gross margin is expected to grow to approximately $11 million.

In our other operations, which includes our rental, technology and E&P businesses, revenues for the third quarter improved to $24.9 million and adjusted gross margin improved to $11.5 million. For the fourth quarter, we expect both revenues and adjusted gross margin in our other operations to be similar to third quarter levels.

On a consolidated basis, we expect total depreciation, depletion, amortization and impairment expense to be approximately $121 million for the fourth quarter. Selling, general and administrative expense for the fourth quarter is expected to be approximately $29 million. We do not expect a meaningful amount of tax expense or cash taxes for 2022.

With that, I'll now turn the call back to Andy Hendricks.

Thanks, Andy. As I've mentioned at recent conferences, one of the challenges that oilfield service companies have had in producing strong returns during previous cycles over the last decade was that most of these cycles weren't of sufficient enough duration to allow service providers the time that's required to raise pricing across their full portfolio of services and customers. This is in contrast to an E&P, which outside of hedges and contracts, has a real-time mark-to-market for the price of their product. I'm very pleased with the progress that is reflected in our third quarter results, and I'm encouraged by our outlook for a multiyear up-cycle.

Our teams did a great job continuing to push pricing across all service lines. And going into next year, we expect to see further pricing increases as many of our existing contracts roll over, especially in contract drilling. As such, I believe we still have significant upside to our current margins and free cash flow. Our expectation is based on our discussions with our customers, which yielded very interesting results from our recent customer survey. While there may be a limited number of E&Ps dropping rigs, the net result is a rig count that will continue to increase in Q4 and in 2023. And while I have heard anecdotal stories of private E&Ps dropping rigs in Q4, a review of our customers doesn't show this to be the case.

Therefore, based on our positive outlook, we have been discussing how best to return our free cash to our shareholders and also how best to describe our intentions. At Patterson-UTI, we have a strong history of returning cash to shareholders, as we have returned more than $1 billion since 2012 through dividends and share buybacks.

In considering how best to return cash to shareholders going forward, we considered the following points. First, we expect that the contract drilling industry will be much less capital-intensive than prior cycles as the major retooling of our drilling rig fleet to AC-powered high-spec and super-spec rigs is complete.

Second, and as we've discussed, we are encouraged by the prospect that this cycle has the strong potential to be a multiyear up-cycle. And lastly, our strong balance sheet and our increasing cash flow visibility from term contracts have Patterson-UTI well positioned to continue returning capital to shareholders. Therefore, as we look forward, we will target to return 50% of free cash flow, defined as cash provided by operating activities less capital expenditures, to shareholders through dividends and buybacks. As such, I'm pleased to announce that our Board of Directors declared a quarterly cash dividend on our common stock of $0.08 per share to be paid on December 15, 2022, to holders of record as of December 1, 2022, which represents a doubling of our prior quarterly cash dividend.

We are also announcing that our Board of Directors has approved an increase to our authorization for share buybacks, where from this point forward, we are authorized to buy back $300 million of shares. We are excited at the prospects for Patterson-UTI shareholders with the potential for returns going forward.

With that, we would like to thank all of our employees for their hard work, efforts and successes to help provide the world with oil and gas for the products that make people's lives better. Dennis, we'd like to open the call for questions.

(Operator Instructions) Your first question is from the line of Scott Gruber with Citi.

Really appreciate the color from the survey, Andy, just given the debate. I'd love to see it obviously. So I guess one concern that such surveys elicit is just that there is an incentive for customers to tell you and peers that material rig adds are forthcoming, which motivates you to take steps to reactivate rigs. And obviously, there's a long lead time on some items today. And so how do you think about kind of going out and kind of validating the survey? I guess, your rig count is up in 4Q, which is supportive, but anything you could speak to in terms of kind of other confirmatory data points that provide confidence to you that the '23 growth materialize?

So I mean these are direct discussions with our customers who our teams work with every day. So this is not something that I feel like requires any further validation. Now one thing to keep in mind is that these aren't approved budgets yet because E&Ps are still working through their budget process and may not finalize that until early next year. But these are based on the direct feedback from the teams at the E&Ps who are having to plan for what's going to happen next, even before approval comes through. So I'm comfortable with these numbers.

The thing you have to remember is we're talking to customers who are drilling horizontal wells, they're using Tier 1 super-spec drilling rigs. And this is a subset of the overall total rig count in the U.S. I think last time I looked, there was still 140 mechanical rigs in the total U.S. rig count, and that's not a part of the sector that we do anything with and those -- that rig count there can move up and down itself.

But based on what we're hearing, our customers and especially the privates are not slowing down their progress. And we didn't see any discernible difference, as I mentioned, between the different classes of operators in terms of who's picking up rigs from now until the end of next year.

Got it. That's very encouraging. I think you talked about CapEx for next year. I know, no budget today, but just some of the major items, obviously, a major peer of yours was talking about maintenance being up kind of in the $1.2 million kind of per rig range. I mean is that a range we should think about for Patterson? And then any early color on upgrades, the number for you next year, prospectively or a range, and the cost per upgrade that we should think about? And then any early thoughts on some of the ancillary spending on EcoCell and other items?

Yes. Scott, this is Andy Smith. Look, again, we haven't gone through our budget process yet, but we do -- we have asked our guys, and we've kind of looked around the company and taken the thought -- or taken a look at 2023 CapEx. And so I think that probably the easiest way to sort of frame it is if you look at 2022 and our guidance of $425 million, maintenance capital, obviously, with activity going up, is going to be a little higher. We are seeing a little bit of inflation in maintenance. We're looking at annual maintenance capital per rig now about $1 million per rig. But so if you start with that $425 million, you think of some incremental adds for activity as well as some inflation on maintenance capital.

And then if you think about the upgrades, which we've already announced, the 5 rigs that are under 3-year contracts, those upgrades were prefunded by customers. So we received the cash in the third and fourth quarter of this year. But that CapEx from an accounting standpoint will hit next year. So that's about $35 million to add to that number. So if you think about that plus kind of where we ended up this year, all in, I think the number totals kind of right around the $500 million range, plus or minus $500 million. So that's kind of the number that we're targeting at this point.

Your next question is from the line of Luke Lemoine with Piper Sandler.

Andy, you had a breakout quarter in your pressure pumping results. Can you talk a little bit about how you see this progressing past 4Q, either kind of on a gross margin basis or GP per fleet?

Well, let me kind of describe it more in relative standpoint. So as we get into Q4, we see a little more white space in the calendar. And we've had a lot of discussions about what's really driving this. Is it budget fatigue? What else is going on? And really, it's not so much budget fatigue for our customers in pressure pumping. It's really that things have been so efficient we're starting to bump up against the drilling rigs. And so we're seeing some white space in the fourth quarter. And I think in the industry in general, that's maybe happening as well because I hear a number of comments about the efficiencies in pumping operations.

But I think as the drilling rig count will continue to increase going forward that, that will help alleviate that. What it means is, essentially, there's probably no real DUCs out there because the pumping spreads are close to the drilling activity. Then going forward in Q1, I expect our pumping results to move back towards what we saw in Q3 with the caveat of cold winter in the Permian Basin in New Mexico, which can slow operations sometime in January. So while we're seeing some white space in the fourth quarter, I think that starts to disappear in the first quarter and the results get closer back to where we were in the third quarter of this year. Does that make sense?

Yes, yes, absolutely. Kind of maybe looking more during the better weather months in '23, 2Q and 3Q, I mean it seems like there's potential upside from 3Q '22 results. Is that fair?

Yes, that's fair. We've got holidays at the end of this quarter, but then we get a little bit of winter in January, sometimes February in Permian, and then things start to improve from a weather standpoint. And there's no reason why we can't duplicate what we've done in Q3 outside of those circumstances.

And then on your rig survey with your customers, those incremental adds you were talking about, were those all super-spec rig adds or just rig adds in general? If those were super-spec, how would you characterize that?

Yes. In general, these are our customers who are looking to add super-spec class rigs. And again, this was our customer base across our drilling business, our pressure pumping business, our directional business, our rental business. We went broadly across our entire customer base for the company.

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

I just want to stay on that survey. So those 90 rigs added through 2023. Wondering what does that imply to you as far as total rig adds for the market? And then of those 90, how much share do you expect to get in your rig additions? And then of those rigs that you're going to add, what's the level of CapEx upgrades required? I know you broke it out for us in those first 34 rigs and the next 30. Just an update on where you are there and the dollar per rig cost to get those rigs deployed.

Yes. So this was a sample of our customer base, so a subset. So when you total it up, there's the potential for more rig adds than what we were just describing because this was a little over 70 customers that we've talked to and gathered data from. So there's potential for more rigs to be added than that. When we look at ourselves and what we will likely do with various customers and what we will likely do in terms of reactivations and some upgrades, our rig count add in 2023 is probably in that 15 to 20 rig range.

And then Andy gave you some color on what we're expecting in the CapEx for different reasons in that, plus or minus $500 million. And that's a high-level look at it for '23 as we haven't gone through the budget process yet, but that gives you some idea of that total.

Got it. That's helpful. Switching over to pressure pumping. I know you just ran through your expectations as far as where EBITDA per fleet can trend by the end of this year into next. But could you break it down another level for us? Can you talk about the differences of utilization, pricing and vertical integration? Obviously, this is a historic mark for you guys. It's setting a new floor in profitability. But what has really driven that between those 3 buckets of utilization, pricing and vertical integration as we think about from now through the end of next year?

Yes. As I said, it's really across the organization in pressure pumping from the marketing teams pushing pricing and keeping the pricing up at the -- towards the leading-edge levels where we can, where we have that ability in our agreements. The operational efficiency that we're seeing from the operations in the field where we're just getting more stages per week, per month, per quarter and the operations support to make sure that maintenance is done, and we have pumps that work and we have blenders that work. And so the business is running really well these days, and we're just really pleased with the overall successes there.

Your next question is from the line of Don Crist with Johnson Rice.

On your term contracts, I calculate you're just under 30% termed out for the next 12 months or so. What is your just general thoughts on where you can push that to? Or do you have any expectations of getting above 50% there? Or just general thoughts around term contracts going forward.

As we came out of this bottom of the cycle, we were keeping any agreements and contract terms very short because we knew we had upside in pricing. And as we have -- begin to push pricing up, which -- this year, pricing has moved faster than probably it ever has historically in our industry. And so we were reluctant to start signing in and layering in longer-term contracts until we could push pricing as much as we could. But like an investment portfolio, we have a long-term view of this, and so we started layering in term contracts into the portfolio of contracts that we have and signing up longer ones. The longest we signed is the 5 rigs for 3 years, but we signed other terms in the year, 1.5 years, even up to 2 years for some. So we've got a blend right now.

And as we continue to see leading-edge rates move up next year, which I think they will, we'll probably layer in some more as well, but we're measured in that process. We still want to be able to capture the upside, but at the same time, we do think it's prudent from time to time when it makes sense for the right customer and the right project to sign a long-term contract.

I appreciate the color there. And one more for me. The supply chain, obviously, was super tight earlier this year. It seems like it's loosening some. Can you just give us general thoughts on the supply chain and how that's progressed through the year? Is it much better now or a little bit better now than it was earlier this year?

I would say supply chain is still tight, and that's still one of the constraining factors in growth, and that's what's keeping the rig market tight and the pressure pumping market tight. Supply chain is still tight. What I think has evolved is how we've had to manage that where we might have had to plan 6 months and 9 months ahead to get certain things. Now we're planning a year ahead to get certain things. And so it's really an adjustment on our side on how we manage the supply chain, but it's still tight.

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

Sorry to beat around on the survey, right, but I think it's important. So let me ask another one on that. First thing, obviously, commodity prices have been really volatile, right? September especially, we saw the 12-month WTI strip going to the low 70s, I think 72, 73 rate, right? So if you can help us on when the survey was carried out, how much do you think commodity price is scaring E&Ps or not scaring E&Ps, right? Just give us some context on that and where you think sensitivity lies. How far do you think oil prices might have to fall before they revisit their plans?

Yes. So that -- all these discussions with customers were happening towards the end of September and early October to give you that time frame of what commodity prices were doing at that time. But I can tell you the commodity prices have had -- the movement in commodity prices have had no effect on any of our customers' plans. There just hasn't been enough movement to cause anybody to rethink what they're doing. And we've even had those discussions just to double check. And we've seen some downward movement in commodity prices over the last few months. But even that downward movement wasn't enough to change plans of any customers that we had.

Okay. No, that's good to hear. Perfect. And then one thing, right? You're one of the only companies -- I think, in fact, the only company which has a big footprint on both the drilling and the pressure pumping side, right? And I think both those markets are clearly really tight. But if you were to compare and contrast those 2 markets between rigs and frac, which one do you think is more attractive for you to deploy more capital going forward?

We find both of these businesses attractive, and their level of attractiveness kind of changes at different points in the cycle. If you look back to 2021, our frac business started to grow and pricing started to move up faster earlier than the drilling business probably by about 6 months. And we still see some upside in pressure pumping pricing as we get into next year, but drilling is about -- it was lagging about 6 months behind that cycle on pressure pumping, but we're very pleased with how both of these businesses are performing. We're pleased with the returns in both of these businesses and the amount of free cash flow we're getting.

Okay. Awesome. Andy, quick one on cash taxes. I think you talked about that on 2022. No meaningful cash taxes. How should we think about 2023 from a cash tax standpoint?

Yes. I wouldn't expect that we're going to have a lot of cash taxes. We'll get better guidance on the next call. We may have some small amounts in 2022 and 2023 related to both Colombia or a little bit in Colombia, but more state. But generally, on a federal -- from a federal standpoint, we shouldn't have a lot of cash taxes.

Your next question is from the line of Keith MacKey with RBC.

I just wanted to start out on drilling OpEx. It certainly has moved higher across the industry. Now around $18,000 a day, it hasn't moved as much as rates, obviously. But with more longer-term contracts signed, can you just talk about how insulated you might be against future increases and what you think is driving the increase in the labor OpEx? And will that continue?

So over the last year, we've had to give 2 pay raises in the field operations, whether it's for drilling, pressure pumping, et cetera, here at Patterson-UTI. The first pay increase we gave, which was about a year ago, was really an adjustment for the market because -- and especially in drilling, we had not been able to give our teams pay raises since the downturn of 2015 happened. And so we were able to give one pay raise about a year ago. And then the second one we did was really more of a cost-of-living adjustment as well to factor in the inflation that we're seeing here in the U.S.

And so those 2 have happened recently. I don't anticipate any broad changes in that going forward. But there's other things happening as well. We're seeing lubricant prices move up. We're seeing some other things move up. So there is a little bit of inflation still happening. Now one thing to remember as well is when you're looking at our cost per day in drilling, that's a fully loaded cost per day for that business, which includes R&E, that includes other things that others may not include in that number, but it's fully loaded burden from an engineering and operations standpoint for that business.

Got it. And maybe just shifting to the pressure pumping, the acquisition of the horsepower. Do you see there being -- or do you see opportunities to do more of that type of stuff? And maybe if you could just talk about any metrics you can give around, say, what you might have paid for that versus what it would cost to have acquired that horsepower on a -- if it were a new kind of thing?

So this was kind of an unusual opportunity that came up where there was a relatively small business in West Texas in the Permian that had relatively new equipment, but it was only being used for low-pressure pump-down. So it wasn't really seeing any type of harsh use that we would typically use in the frac business. And so it just so happened that these pumps were available. And yes, they did have hours on them, but it was relatively soft hours compared to what we do. So we were real pleased with the condition of the equipment. And I'm not going to get into any numbers, but we did get a significant discount off of buying new equipment. So we were able to pick up Tier 4 equipment.

Now with that equipment, we'll very likely end up working most of that into the existing fleets where we can take these Tier 4s, we can add upgrade kits to add dual fuel to some of these. And so we will continue to upgrade what we're offering in the market and also the earnings power of our existing spreads.

Your next question is from the line of Sean Mitchell with Daniel Energy.

Thank you for the color around your survey. It's very helpful. When you think about '23, can you rank where you see the greatest demand from your customers or the incremental demand you're seeing in the form of the survey or otherwise? Is it Permian, Haynesville, Marcellus or give us any color around -- are you seeing more demand from one basin or the other?

We're seeing -- we went through this the other day just to double check, but we're seeing growth in all the basins, some more than others. We're even seeing rig adds in the Marcellus, Utica, but primarily, it's going to be Permian, Mid-Con, a little bit of the Bakken as well. But we are seeing rig count increases in all the basins.

Okay. And then maybe a follow-up. Just as we've listened to the call so far, lots of oil service companies highlighting what international looks like in '23. I know you have rigs in Colombia. Is there any opportunities outside of Colombia that you guys are thinking about?

Well, the Colombia business is doing really well for us. Really pleased with how that team is running that business and their performance and execution that they have down there. That team has a great reputation. It may give us an opportunity in the future to expand next door -- or into Ecuador, but we'll just have to wait and see how that plays out.

(Operator Instructions) Your next question is from the line of David Smith with Pickering Energy Partners.

Wanted to circle back to the comments about leading-edge Lower 48 rates at $40,000 a day, including ancillary services. Could you please remind us where you see average ancillary services? Or just alternatively, how you would characterize leading-edge-based pricing relative to the update you gave 3 months ago?

Yes, it's still been moving up, and I expect it to continue to move up. Right now, we're seeing it around plus or minus $40,000 per day at the leading edge including drill pipe, any extra crew that an E&P may want, including forklifts, light plants, all the ancillary-type services that we may provide, rig moves, et cetera. But when you average it all out, you're at that plus or minus $40,000. But with the rig count for horizontal rigs continuing to move up into next year and through next year, I expect still some more upward movement on that number.

Okay. I appreciate that. Do I remember correctly that you're running about 7 gas [grading] fleets out of the 12?

Yes. 7 of the frac spreads that we run are primarily natural gas.

So just building on your comments about integrating that opportunistic purchase into the fleet with some dual-fuel conversions. How do you think about the cadence of converting the remainder of your fleet? Does that just -- I didn't know if you might be expecting more opportunistic acquisitions that might allow retirement of older horsepower. And any thoughts on what you're seeing currently for pricing of Tier 2 diesel legacy equipment versus Tier 4 dual fuel?

So we're still seeing the overall frac market tight with the exception of a little bit of white space here in the fourth quarter, but it will stay tight next year. Yes, we do get a premium for running Tier 4 dual fuel, and so this was a nice little tuck-in for us to be able to do. But it was a bit unique. I'm not sure there's really many others out there like this. But we were pleased to be able to do this, and it will allow us to do some more conversions and then increasing pricing with whoever is going to be running that frac spread when we do that.

But it's not really a cadence that I would describe it. I would just describe it as an opportunity to be able to buy some Tier 4 pumps and work it into our system and push the margin where we can.

Your next question comes from the line of Dan Kutz with Morgan Stanley.

Just wanted to follow up and confirm something on kind of the frac equipment line of questioning. Am I still understanding correctly that there's not really any plans contemplated beyond this potential 13 fleet to reactivate any of that equipment? Or could you see a scenario where you were taking some of the idle equipment that you have and investing in some upgrades and putting anything back to work beyond that potential 13 fleet next year?

So right now, we're working 12 and our current view is that we'll continue working 12. We haven't spent much time to decide whether or not we would activate #13 yet. Adding these pumps gives us more flexibility to do that with Tier 4-type equipment, but we haven't made that decision. So we'll work through that over the next few months and continue to evaluate. Again, we were getting into white space in the fourth quarter. So there was no point in trying to do something in the fourth quarter. We may do something in '23, but we just haven't decided.

Our primary focus right now is returning cash to shareholders. We've got a new commitment out there to return 50% of our free cash flow, and that's our focus. So we're also trying to manage the CapEx versus the EBITDA to make sure that we're maximizing what we can return to shareholders.

Great. And maybe just staying on the shareholder returns theme. So I wanted to just clarify how you guys are thinking about hitting that 50% of free cash flow target. If I'm just looking at consensus EBITDA for 2023, it's around $900 million. Maybe that's conservative. It's just that, that doesn't assume a lot of growth beyond your 4Q guide. And then if we back out the CapEx, the $500 million that you spoke to, that gets to about $400 million. So 50% of that dividend seems like it's about $70 million next year. Is the flywheel kind of for buyback to kind of try and hit that 50% target? Or is there a potential for dividend increases or special dividend? Just wanted to get a little bit more clarity on your strategy there.

I think all options are on the table. We've described what our intent is with the dividend where we're really pleased that we've been able to double it now going forward. So that has -- that will be roughly $71 million, $72 million a year in cost to be able to do that out of that free cash flow, and then we'll try to look at the rest with share buybacks, but all options are on the table.

This concludes the Q&A portion of today's call. I will now turn the call back to Andy Hendricks for any closing remarks.

Thanks, Dennis. I just want to thank everybody who joined the call today. We appreciate the questions. And again, I'd like to thank all the employees of Patterson-UTI for the great work that you're doing. Thanks a lot.

This does conclude the Patterson-UTI Energy Third Quarter 202 Earnings Conference Call. Thank you for your participation. You may now disconnect.