Good morning. My name is Colby, and I will be your conference operator today. At this time, I'd like to welcome everyone to the Patterson-UTI Energy Fourth Quarter 2022 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. [Operator Instructions] Thank you. I will now turn the call over to Mike Drickamer, Vice President of Investor Relations. You may begin.

Thank you, Colby. 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 three months ended December 31, 2022. Participating in today's call will be Andy Hendricks, Chief Executive Officer; Andy Smith, Chief Financial Officer; and Mike Holcomb, Chief Operating Officer. A quick reminder that statements made in this conference call that state the company's or management's plans, intentions, Targets beliefs, expectations or predictions for the future are forward-looking statements. These forward-looking statements are subject to risks and uncertainties and 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 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. 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 fourth quarter conference call. We are pleased to report another quarter of solid financial results with improving profitability. Adjusted EBITDA grew every quarter in 2022, with fourth quarter adjusted EBITDA almost 5x our fourth quarter 2021. Our fourth quarter results were driven by continued improvement in pricing and exceptional execution. Also, during the fourth quarter, we returned $74 million to shareholders through our regular quarterly dividend and $57 million of share repurchases. Additionally, we retired $22 million of long-term indebtedness through open market purchases. As we look ahead, we remain optimistic that we are in a multiyear up-cycle. Tier 1 super-spec rigs and premium pressure pumping equipment are effectively sold out due to the strong growth in activity over the past 2.5 years. The high demand led to a notable increase in leading-edge pricing in 2022, and high utilization continues to support current pricing levels. We anticipate a significant increase in earnings and cash flow during 2023 as we continue to reprice drilling rig contracts higher to current leading edge rates. From a big picture perspective, we expect oil will continue to be the primary driver of our industry, and we expect oil prices to remain at acceptable levels to support activity for the foreseeable future. With respect to natural gas drilling activity, which is a much smaller part of the total industry rig count, our primary exposure is in the Northeast. Due to constraints on gas takeaway capacity in the Northeast, operators have been careful to align their drilling and completion plans with long-term goals and have tightly managed their production growth, making the Northeast less volatile than other gas markets. As a result, our customers in the Northeast are typically well hedged and have our…

Thanks. Net income for the fourth quarter was $100 million or $0.46 per share, up from $61.5 million or $0.28 per share in the third quarter. Our contract drilling business had a significant sequential increase in average adjusted rig margin per day in the U.S. of $2,970. This growth was driven by successful contract renewals at more favorable pricing than projected, which resulted in a $3,160 increase in average revenue per day in the U.S. On a year-over-year basis, in the U.S., average rig revenue per day increased $9,800 or 44% from the fourth quarter of 2021 to the fourth quarter of 2022. At December 31, 2022, we had term contracts for drilling rigs in the U.S., providing for approximately $830 million of future dayrate drilling revenue, up from approximately $710 million at the end of the third quarter. Based on contracts currently in place in the U.S., we expect an average of 87 rigs operating under term contracts during the first quarter of 2023 and an average of 56 rigs operating under term contracts for the full year. In Colombia, fourth quarter contract drilling revenues were $15.1 million and adjusted gross margin was $4.9 million. For the first quarter, we anticipate that our average rig count in the U.S. will be 130 rigs. We also anticipate that average rig margin per day in the U.S. will increase by approximately $1,000, which allows for an increase in average rig cost per day related to rig reactivations and cost inflation. In Colombia, we expect to generate approximately $9 million of contract drilling revenue during the first quarter, with adjusted gross margin of approximately $1.2 million. In pressure pumping, revenues and margins improved during the fourth quarter. Pressure pumping revenues increased to $307 million, and adjusted gross margin increased to $86 million.…

Thanks, Andy. 2022 was a great year for the company given the rapid growth in margins resulting primarily from improved pricing. In contract drilling, we expect the continued high utilization of Tier 1 super-spec rigs and premium pressure pumping equipment to be supportive of current leading edge rates. These rates provide a strong foundation for earnings growth as we continue to reprice drilling rig contracts higher to current leading edge rates. Looking forward, overall, I am very upbeat for 2023 as I see this as another year for growth in margins and significant growth in free cash flow. Throughout the year, I expect the overall U.S. rig count for the industry will continue to increase, especially for super-spec rigs, driven by increases in the oil basins, and acknowledging that there may be near-term softness in gas basins outside the Northeast. We believe the Tier 1 super-spec rig count continues to increase over the next year, and we expect completion activity to increase as well. Higher activity combined with the tightness of equipment in these markets should protect and support the leading-edge rates for rigs and for services over the next year. Given our outlook for significantly higher profitability and cash flow in 2023, we continue to target a return of 50% of free cash flow to shareholders through a combination of dividends and share buybacks. 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. Colby, we would now like to open the call to questions.

[Operator Instructions] Your first question comes from the line of Arun Jayaram from JPMorgan Chase. Your line is open.

Good morning. Andy, I was wondering if you could shed some thoughts. I know you guys did a survey in October, 70 of your key customers and highlighted a pretty meaningful planned increases in the rig count. Obviously, the gas market has changed quite a bit since that time. But as you do a postmortem on that what’s your thoughts on demand because it is trending lower than you thought just a few months ago? And I have a follow-up on that.

Sure. No problem. So yes, we did that survey back at the end of September, early October. At that time, WTI was trading around $85 a barrel and natural gas was certainly much higher. And so I think there was a little bit more enthusiasm from the E&Ps that we talk to about what their rig count was going to do. We’ve certainly seen some changes. Now the interesting thing is, as we work through the year, we have seen changes in the rig count, but when you look at the breakdown of AC rigs, and especially when you look at what we’re doing with Tier 1 super-spec rigs, that market has held steady. So while we’re not seeing overall growth in the rig count, because you’ve seen SCR mechanicals get released over the last few months, the high-end market that we participate in is certainly keeping a very high utilization rate and supporting the leading edge pricing.

Great. And just my follow-up, through a decent amount of market observers, including our own, we could see a 30 to 50 rig decline on the gas rig count in terms of trying to – the supply response call it, in terms of the decline in gas prices just to balance the market. Is it your estimation, Andy, there’s enough demand on the oil side to more than offset the declines that potentially could happen on the gas side?

Yes. And we’re already seeing that. We’re already seeing where we’ve had two rigs go down in gas, and we’re seeing discussions and requests for rigs to go into oil markets. So I think that while rigs may be coming down, we’re also reactivating rigs. And when you look at net-net, what we’re doing and what we’re seeing with customers, we still expect our rig count to grow in 2023. Remember, we’re not participating in the SCR mechanical market. Those types of rigs aren’t on long-term contracts. They’re easy to release. So outside of the Northeast, we have a large number of rigs in gas, and those are primarily under term contracts with hedged customers. There’s going to be some softness in the natural gas markets outside of that one, and we certainly recognize that. But when we look at what’s happening with AC high-spec super-spec rigs, we still see a very tight market for those rigs.

Great. Thanks a lot Andy.

Thanks.

Your next question comes from the line of Jim Rollyson from Raymond James. Your line is open.

Hey, Good morning, guys. Andy, on the reactivation of the 13th spread, just kind of curious to get your view and decision process when you guys go through that? Just obviously, last year, everything was up and to the right and with the rig count kind of more flattening out from the trajectory we saw…

Yes. We’ve been looking at what it would take to reactivate that 13th spread for over a year now since we’ve had 12 running. And what’s happened in the market is as we would start to slowly reactivate pumps and add more pumps to what we have in circulation across all of our spreads between active in the field and maintenance, getting ready for spread 13 and doing the calculation on that, what we’ve been seeing is that existing customers have been absorbing the pump supply. And I believe that’s happening across the industry. The amount of horsepower per spread for the type of high-end work we do in places like the Delaware and the Utica, we’ve seen E&Ps that just want to pump at higher flow rates and higher pressures. And we – those are the high-end markets that we participate in, in pressure pumping. And so we’ve seen that absorb. So in other words, what’s happening with our 13th has just been pushed. And so while we thought there might have been a chance to do it at the end of 2022, we’ve just been absorbing our current horsepower that’s been active into existing spreads. But as we get into 2023, we’ll be able to free up some of that horsepower, and we should have sufficient towards the end of 2023 to activate that 13 spread.

So that’s a late year add, it sounds like?

It’ll be a late year add.

Okay. And then just as a follow-up on the share repurchase side, obviously, good to see you guys actually executing on the program during the fourth quarter. Curious how the plan is for that? Is that just kind of as you generate free cash flow over and above the dividend that you’ll buy it kind of periodically across the year? Or is it opportunistic? Or how do you see that?

So I’ll start, and then I’ll hand it over to Andy Smith. We’re committed to giving at least 50% of our free cash flow back to shareholders through dividends and share buybacks. As a publicly traded company, we have blackout periods during the year. So there’s only certain windows that we can get into the market and acquire shares, and we’ll do our best at those points, outside of the dividend when we’re looking at buybacks to buy back shares in those windows that are open to us. I’ll hand it over to Andy.

Yes, I don’t have a lot to add to that other than to say, again, reiterate that we are committed to our return metrics. So again, that 50% of free cash flow coming back to shareholders in some form or another, we’ll be opportunistic more on the buyback side, but certainly, we’re committed to that 50% return.

Great. Helpful. Thanks.

Your next question comes from the line of Scott Gruber from Citigroup. Your line is open.

Hey guys, good morning.

Good morning.

Andy, how many rig reactivations are embedded in the budget this year? And of those, how many have contracts today? And what kind of line of sight do you have for additional contracts on the reactivations?

So right now, we’re planning eight reactivations in the CapEx budget, and we have line of sight on those eight. So we see – we think our rig count still grows. We do recognize there’s some near-term softness with the gas markets. But I think, overall, we’re going to see growth through 2023.

Got it. And just circling back to Arun’s question on potential downside risk on the gas side. Just help us think about how do you guys – if the downside case kind of materializes, how do you think about kind of marketing your fleet? I mean do the reactivations kind of replace some older rigs? Or do you modulate those and kind of pull them back? And how do you think about kind of managing the crew count? Just trying to get a better sense of kind of as you think about scenario analysis, kind of what’s the management of the marketed fleet in more of a downside scenario?

Yes. And we certainly recognize there’s potential for a downside case, but I think it affects different companies differently. And back to the discussion of Northeast versus the other gas basins, the way that our customers have been behaving, and in discussions with our customers, we believe that market remains relatively steady for us in both drilling and completions. Our customers are well hedged up there. The rigs are working under long-term contracts. So if there’s a downside case materializing, it’s likely happening outside of the Northeast, whether it’s East Texas, North Louisiana, Haynesville, maybe areas of South Texas, Oklahoma, where you still have a lot of gas production. But with the number of rigs we have working in the Haynesville, that’s only 10% of our rig count. So, I think we’re kind of limited in a downside case in those basins.

Got it. Appreciate the additional color. I’ll turn it back. Thanks, Andy.

Thanks.

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

Hi, Andy and Andy. Just quickly following up on the prior question from Scott. I think you said your CapEx budget is baking in eight rig reactivations. I’m just trying to understand, right? I mean, how flexible are you going to be on that approach? If you don’t get the right contract, right duration, right pricing, how willing would you be to say that, okay, I’m not reactivating eight rigs, I’m only doing four rigs or five rigs or whatever the number is, right? I’m just trying to understand the flexibility because, again, I’m looking at the stock. So your stock is down 10% after a fantastic fourth quarter, right? Obviously, people are concerned about demand, and I would appreciate if you can talk to your flexibility in that decision making process?

No, we’ve always had flexibility and are available to react, and we’re not going to spend CapEx if it’s not necessary. But one thing I’ll say is there is enough utilization out there to support the leading-edge pricing that we have today. I do not expect any change in leading edge pricing. I see a 2023 that we will continue to reprice rig contracts from early 2022 up to the 2023 rate. And so we’re still projecting steady growth in margins, steady growth in free cash flow throughout 2023 because of that, even if we didn’t activate any rigs, but we will because we do have line of sight. And so we’ve got eight rig reactivations planned in our CapEx budget. We’re certainly not ignoring what can potentially happen in the gas markets outside of the Northeast, but we think it’s a limited effect on what we do because of the strong demand for Tier 1 super-spec rigs.

Okay. Now, Andy, I appreciate that. And then quickly in terms of what to expect in terms of how rigs reprice through the course of 2023. Obviously, very solid improvement in average revenue per day. In the fourth quarter, more than $3,000, you are guiding to, I think, if I got the number right, the cash margin increasing $1,000 in the first quarter. First, quickly, maybe you can talk to the split between how much revenue per day is going up versus OpEx, because first quarter tends to be seasonally just a higher OpEx quarter due to a bunch of factors? If you can talk to the split between that. And then just in general, what should we expect through the remainder of the year? How does your book reprice through the course of the year?

Yes. I think what’s getting lost in all the discussion right now is our ability to reprice rigs from early 2022 levels to where we are today in 2023. We’re probably going to reprice around 30 contracts in the first half of 2023. Some of those contracts have rigs that are still working at $19,000, $20,000 a day. Those are going to be going up to $35,000 a day, plus when you add in drill pipe and extra people and the other upgrades people want, you’re at rig rates around $40,000 a day. These are still huge movements in revenue per day and margin per day in repricing these contracts. And that’s still going to happen because the overall utilization for Tier 1 super spec is still high despite what’s happening in recent releases of SCR mechanical rigs that just doesn’t affect what we’re doing right now. Andy, do you want to comment more on revenue?

Yes. So on revenue per day and cost per day, you can expect revenue up about $1,500 a day and cost up about $500.

Okay, perfect. Okay, Andy and Andy, thank you very much. I’ll turn it back.

Your next question comes from the line of Kurt Hallead from Benchmark. Your line is open.

Hey good morning everybody.

Good morning.

Hey Andy, it sounds like you guys got a unique line of sight on some opportunities that some of your competitors didn’t seem to kind of discuss on their conference calls today to activate these eight rigs or so. Maybe give a sense of how that cadence may play out? Is it – you mentioned the frac crew coming on could be later in the year. Do you think the same context could hold true with the land rates, were there going to be more of a back-half weighted kind of rollout?

So for the activations on the rigs, they’re relatively steady throughout the year. And then, as we discussed, the 13 spread is more of a Q4 event, but five of these we announced back in September, so I don’t know why this is so hard to understand. We’ve got three more on top of five. That’s not a big number. So, we’ve got line of sight on this, and that’s how we see this progress.

Okay. Great. And then in the context of the frac crew addition coming up here, is that a situation where you have identified a customer and a contract opportunity for it? And are they waiting on that crew to come out? Are you going to be actively marketing it between now and then?

So, we’re in discussions. In the pressure pumping market, we don’t participate or try to compete in the lower end, lower pressure Midland Basin or lower pressure Marcellus. Our crews are set up and working the higher end, higher technology, deep Utica, deep Delaware, higher pressure, higher rates and those areas. And so we’ve got a great reputation for what we do at that level of performance. And so we’ve got a few customers that are looking to expand what they’re doing because they’re going to be adding drilling rigs this year. And so yes, we do have some line of sight on possibilities for our crews.

Great. And then last follow-up here. You mentioned repricing 30 rigs in the first half of the year. What point do you think you’ll have the vast majority of your rig fleet on, let’s call it, that $35,000 to $40,000 a day kind of leading edge?

It’s certainly front-end loaded in the year, but it will continue throughout 2023. And I’ve discussed this a few times, but just to kind of clarify for everybody. I don’t think we get everything up to leading edge in 2023. I think some of this continues into 2024, but certainly heavily weighted into the first half of 2023.

Thanks. Appreciate, Andy.

Thanks, Kurt.

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

Hi, thanks and good morning. Just wanted to start out. Maybe if you could just take a bit of time here and compare and contrast what you’re seeing between the land drilling and pressure pumping markets? Do you expect one to be stronger than the other in terms of 2023 profitability, ability to move rates or utilization of equipment?

So, I’ll start with the pressure pumping. Our teams have done a really good job continuing to push pricing. So, we still – we have a fair amount of – a good percentage of our pressure pumping that’s working at that leading edge pricing. We’re producing top quartile EBITDA per spread right now. I think the real opportunity for us is on the drilling side because of the number of term contracts that we were signing in early 2022. And so we’re – like I mentioned, we’re going to be repricing about 30 contracts in the first half of 2023, and these are big movements on these contracts just to get customers up to where the market is today. They’ve certainly had a huge benefit over the last year with the rig rates they’ve been paying versus where the market’s been moving to. And so these adjustments are going to happen in 2023. And that’s why I see that – I think that’s the underappreciated part of the story is our ability, even if we weren’t putting out any more rigs, even if I said our rig count was going to be flat, which is not, what we’re projecting, we’re still going to grow margin and grow free cash flow because of the repricing.

Got it. Makes sense. And maybe if you can just talk a little bit about what you’re seeing in terms of operating costs on the drilling and the pressure pumping side. OpEx per day was about $18.3 [ph] or so in Q4. Where do you see that going for drilling? And then maybe if you could just comment a little bit as well to the extent you can on the pumping side?

I’ll hand that over to Andy Smith.

Yes. On the drilling side, look, we’re still seeing a little bit of cost creep. We talked about looking in the first quarter with an increase of about $500 per day. So you can do the math there. On the pressure pumping side, same thing, although probably a little bit more – less so maybe on labor and a little bit more on some of the R&M. Inflation is real on that side of the business. So it’s crept up a little bit, but pricing has stayed ahead of it. So, we’re still seeing net pricing gains.

Okay. Appreciate the color. Thanks very much.

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

Good morning, gentlemen. How are you all?

Great.

Two questions for me. Number one, in the past, you’ve done a lot of work on the overall rig count. I know a lot of the analysts are in print saying that that it could pretty much moderate this year, maybe dip in the first half and kind of build up in the second half of the year assuming that the gas strip comes back. Can you offer your thoughts on how you see the land rig count kind of progressed through the year and possibly where it may end this year?

So, I need to kind of parse that into two different types of rig classes because our visibility in our drilling business is really around AC high-spec, super-spec rigs. And then SCRs and mechanicals just kind of do what they do and are treated more on a spot market. But the AC high-spec, super-spec rigs, primarily working on term contracts and getting repriced right now, we’re seeing that market to be tight near 100% utilization today. We expect that our rig count in that sector continues to grow in 2023. Now if you look at SCR mechanicals, those are down probably 30 rigs since the beginning of this year, but that doesn’t affect what we do. That’s just a separate part of the market from where we participate. And so it’s kind of hard to predict what that part of the market is going to do. Those aren’t necessarily the types of customers we work for. And that you’re going to see some movement in the rig count because of what’s happening in natural gas. But I just don’t – we don’t have any visibility that, that’s really going to have any effect on Tier 1, super-spec rigs and the overall utilization and leading-edge pricing there because of the overall demand. We’re still in discussions with E&Ps in the oil basins on increasing activity in the oil basins.

Okay. And shifting gears just to the cost side and supply chain, in particular. Rolled steel pricing has come back quite a bit, but pipe pricing really hasn’t moderated at all. Are you seeing – just with a little bit of weakness in the overall rig count, are you seeing the supply chain kind of loosen up a little bit and pricing kind of moderating some?

So new drill pipe, which is what we buy, that’s consumed in the way we do it on our rigs. We buy a lot of what we call high torque, double shoulder drill pipe. We rent a lot of that pipe on the market. That’s not the type of pipe that’s used on SCR and mechanical rigs. So when SCR mechanical rigs slow down, it doesn’t change anything in the high-spec drill pipe market. And double shoulder, high tour connection drill pricing has been moving up, lead times haven’t really come down, it’s still around a year lead time for buying pipe. So that market for high-end drill pipe, which we use on Tier 1 super-spec rigs, is still tight. We still have to order a year in advance, and that’s not going to be affected by low end rigs slowing down.

And anything on maybe mud pumps or any other equipment that may be duplicated on those lower-quality rigs?

No. It’s – these are just very different systems. Ours are AC motor-driven mud pumps that are not the same as what you have on our SCR mechanical rig.

Okay, I appreciate the color. Thanks. I’ll turn it back.

Your next question comes from the line of John Daniel from Daniel Energy Partners. Your line is open.

Hey, good morning guys. First one for me, not in the modeling right now. The blended hydrogen project that you talked about, Andy, can you just elaborate on what was exactly was involved? And then that’s kind of a long ways off, just the speed of adoption and opportunity center? And how did it go the trial?

So overall, the trial went really well. The engines worked successfully on a blend of hydrogen along with the natural gas, really excited about how that test went. It wasn’t a high percentage of hydrogen, but the point was just to try to test the systems, make sure that the spark ignition engines are still going to function properly under that type of environment. And overall, good. I would say that – when you step back, technically, you use success, the next step is to try to increase the percent blend of hydrogen. But overall, the economics for hydrogen, I would say, today still probably presents some challenges. Now I think that market has potential to move quickly. It’s about how do you procure hydrogen, how do you transport hydrogen, storing it and then putting it into the systems? But I think all those things are going to get worked out, and I think over the next year or so, we’ll probably see more of an uptake there. And we’ll be doing some testing on the pressure pumping systems too, and blending hydrogen with the natural gas on there as well this year.

Okay. Can you say where – what region that was tested in?

We did our test up in the Northeast.

Okay, cool. The 13th fleet when it gets reactivated, is it safe to assume that’s a Tier 4 dual fuel upgrade?

Correct.

Okay. And then what type of contract duration are customers willing to entertain today versus, call it, 6 to 12 months ago?

We’re still seeing discussions in a year or more for contracts for drilling rigs.

Yes. Okay. So I mean that kind of validates, if you will, then [indiscernible] to dumb it down this just the bifurcation of what’s going on. Because when I hurdle everyone is trying to get a sense for where the rig count is going, but the way you describe it, seems to me, you have the scenario where the overall rig count might lead a little bit lower, but those with like you all with high-spec rigs continue to see your market share improve?

That’s certainly our view. And I am doing my best to explain today. The SCR mechanical rigs are going to do what they do on the spot markets because they’re not covered with term contracts, and we don’t operate those rigs. So I think it’s going to affect the overall rig count because it’s about quarter of the overall rig count, but it doesn’t affect drilling contractors that are running AC high-spec, super-spec rigs.

Fair enough. Last one for me and this not to be a double downer here, but let’s assume that you do see softening in a place like the Haynesville and just make up a number, four to five frac fleets get sort of displaced, if you will. And the owners of those fleets naturally say, "Well, let’s move them to an oily basin." And so you look west, you go to Midland. Is there – is the – do you think the Permian market is tight enough where those four to five fleets plus the incremental ones that are getting reactivated, it can absorb it easily? Or does that then create a headache back half of this year?

So I think there’s two things that are happening in the pressure pumping market that are keeping that market type for equipment that are probably underappreciated unless you’re living it day to day, like our teams are. One is this absorption of increased horsepower per spread is straining us and others in the industry as we try to operate more pumps into those spreads. And so the need to have pump cycling back to maintenance is stretched right now. And so equipment still needs to come into our systems to efficiently operate at the higher horsepower per spread rate. So that’s tight, and that’s going to absorb more horsepower. The other is, the projections of how many spreads are potentially coming out in 2023 is either going to be delayed or it’s back-end loaded because the availability of equipment and engines and pumps is still tight coming from manufacturers. And so the forecast for how many spreads are coming in, I think that gets pushed in the year. And so that’s why I think any spreads freed up coming out of East Texas, North Louisiana, are going to – that horsepower is either going to get absorbed into the increased horsepower per spread, or it’s going to go to work in an oil basin where equipment that’s planned to show up is going to be delayed.

Got it. Okay, thank you for entertaining my questions.

Sure.

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

Hey guys. Not to belabor the point on leading edge, but maybe what would be – Andy, what’s the biggest threat on that $40,000 leading-edge day rate? I mean some investors, the way they look at it, they’ll think a lot of these rigs, the $40,000 supported, the significant CapEx required to reactivate these rigs, they’ve been out for a little bit. They’ve earned their payback. And now given the market churn that you’re seeing, you can move those rigs and maybe doesn’t require that level of leading-edge day rate. I know you talked about utilization being type of maybe what would be the biggest threat in your opinion to see any sort of softening on that $40,000 leading edge?

We have a lot of discussion about that. But at the end of the day, our focus is on margin. Our focus and our duty to our shareholders is to maximize our margin. And so on one side, we’re going to try to protect that leading-edge day rate, and that’s what we plan to do. But on the other side, the demand is just still tight. We’re at 100% utilization. And even if something frees up in the short term, over the long term, in 2023, it’s going to get absorbed back into the system. And there’s no reason for us to price a Tier 1 super spec rig at a lower day rate knowing that eventually, it’s going to go back to work at that day rate. So we just don’t see any risk in 2023 on that leading edge rate.

Got it. Okay. Switching over to international, Columbia. It seems like the guide was a little weak there. Can you maybe talk about how many rigs are active there? Are there any that are going to idle? And then maybe other potential opportunities in the Latin America region where you could move some of those idle rigs out of Columbia into different countries? And just what are the overall growth prospects down there?

Yes. So there has been some changes in the Colombia market. We were working as six, seven rigs, and now our rig count is coming down. It’s – a lot of it’s due to changes in the fiscal set up for the operators down there. The operators are trying to work through that and see how that’s going to affect them. We do expect our rig count to move up again in Colombia. We also see potential for some possibilities in Ecuador as well, and we continue to work on that.

Got it. Great. Appreciate the color. Thanks guys.

Thanks.

[Operator Instructions] Your next question comes from the line of Luke Lemoine from Piper Sandler. Your line is open.

Hey, good morning. I wanted to see if you could talk a little more about the $95 million CapEx in your drilling budget for incremental rev opportunities. Andy, you mentioned premium drill pipe, but what else is in this budget and kind of what paybacks are you getting on these investments? I guess maybe some of this is EcoCell, and could you also just kind of refresh us where you are on that initiative?

Yes. It’s – look, it’s EcoCell. It’s going to be general market upgrades, third pumps, fourth generators, things like that. Drill pipe is a big one, and they’re all pretty good returns. Obviously, a third pump or fourth gen would go into potentially there putting out a new rig or upgrading a rig that’s out working and getting a little bit more rate. On the drill pipe and the EcoCell, those are sort of a la carte items that pay back pretty quick inside of maybe 1.5 years, two years.

Okay, got it. That’s it for me.

There are no further questions at this time. I will now turn the call back over to Andy Hendricks, CEO for closing remarks.

We appreciate everybody’s time this morning. Thanks for dialing-in, and we appreciate the questions. Have a good day. Thank you.

This concludes today’s conference call. You may now disconnect.