Good morning. My name is Colby. 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 speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star followed by 1 on your telephone keypad. If you'd like to withdraw your question, again, press star 1. 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, on behalf of Patterson-UTI Energy, I'd like to welcome you to today's conference call to discuss 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. 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 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. 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 5 times our fourth quarter 2021. Our fourth quarter results were driven by continued improvement in pricing and exceptional execution. During the fourth quarter, we returned $74 million to shareholders through our regular quarterly dividend and $57 million of share repurchases. We retired $22 million of long-term indebtedness through open market purchases. We look ahead, we remain optimistic that we are in a multi-year upcycle. Tier 1 super-spec rigs and premium pressure pumping equipment are effectively sold out due to the strong growth in activity over the past two and a half years.
The high demand led to a notable increase in leading-edge pricing in 2022. 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. 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 drilling rigs under long-term contracts. In the near term, we expect some rigs in gas basins outside of the Northeast will be let go while other rigs are reactivated to go to work in the oil basins. This may have the short-term effect of moderating growth in the rig count, but we expect utilization of Tier 1 super-spec rigs to remain very high, positively supporting pricing. Turning now to my review of operations. During the fourth quarter, our average rig count in the U.S. rose by 3 rigs to 131 rigs, and average revenue per day increased by $3,160. Our marketing team deserves recognition for their effort in achieving this growth, which was the sharpest sequential increase in quarterly revenue per day that we have seen.
Looking forward, our technology will continue to play a key role in helping customers meet their objectives, whether it's in low carbon solutions, where Patterson-UTI has a leadership position with our various technology offerings, or in data analytics and forms of automation and remote operations. We expect that our EcoCell lithium battery system and automated engine power management for drilling rigs will continue to see uptake in 2023, as they have shown to reduce both fuel usage and emissions outputs from drilling operations. We even recently tested hydrogen as a fuel and believe that we were the first to blend hydrogen on an operating drilling rig. We are excited about the potential this has to significantly reduce emissions in the future. In pressure pumping, we saw exceptionally high utilization in the fourth quarter, with limited weather disruptions and minimal downtime during the holiday season, despite the weather.
This outcome was achieved through our strategic alignment with key customers and our focus on efficient operations, which allowed us to capitalize on strong demand and secure favorable pricing for our services. We anticipate the demand for pressure pumping services will remain robust while the supply of equipment will continue to be constrained. The lead times for new equipment, particularly for advanced Tier 4 dual-fuel engines, are still longer than usual, which makes it difficult to quickly add to existing capacity. Additionally, as customers' demands for higher flow rates grow, the amount of horsepower per spread is also increasing, which will further limit the availability of pressure pumping spreads. In 2023, we will continue to convert engines to Tier 4 dual-fuel so that they can use natural gas as the primary fuel and reduce operational costs and emissions.
In directional drilling, we remain focused on technology and service quality, with many new developments to improve wellbore placement and quality. With regards to the downhole tool used by our teams to steer wells, we continue to benefit from the vertical integration of engineering key components for our performance drilling MPact motors and our MPower measurements and data transmission systems. This approach has improved our ability to drill wells faster and with better consistency and to have better control of our costs and supply chain. We are also benefiting from the strategic shift towards higher margin rotary steerable work. In 2022, revenues from rotary steerable work increased to approximately 20% of our directional drilling revenues, up from approximately 13% in 2021. We expect our rotary steerable work will continue to grow in 2023.
I will now turn the call over to Andy Smith, who will review the financial results for the fourth quarter.
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 3rd quarter. Based on contracts currently in place in the U.S., we expect an average of 87 rigs operating under term contracts during the 1st quarter of 2023 and an average of 56 rigs operating under term contracts for the full year. In Colombia, 4th quarter contract drilling revenues were $15.1 million, and adjusted gross margin was $4.9 million. For the 1st 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. For the first quarter, we are experiencing more weather disruptions than normal and therefore expect pressure pumping revenues to be approximately $280 million, with an adjusted gross margin of $72 million.
We expect that revenues and adjusted gross margin will improve in the second quarter with fewer weather disruptions. In directional drilling, revenues improved to $59.5 million in the fourth quarter from $58.9 million in the third quarter, and adjusted gross margin improved to $11.2 million from $10.4 million. For the first quarter, we expect revenues of $54 million with an adjusted gross margin of $9 million. In our other operations, which includes our rental, technology, and E&P businesses, revenues for the fourth quarter were $22.8 million with an adjusted gross margin of $8.2 million. For the first quarter, we expect revenues and adjusted gross margin to be similar to the fourth quarter.
On a consolidated basis, we expect total depreciation, depletion, amortization, and impairment expense to be approximately $123 million for the first quarter. Selling, general, and administrative expense for the fourth quarter of $34.6 million included $3.5 million of mark-to-market adjustments for incentive-based compensation, which is not expected to recur in the first quarter. Accordingly, SG&A is expected to be approximately $31 million in the first quarter. Interest expense for the fourth quarter of $8.1 million included a two and a half million dollar gain from the early extinguishment of debt related to the $22 million of debt we repurchased in the fourth quarter. For the first quarter, we expect interest expense to be approximately $10 million. Our effective tax rate for 2022 was approximately 8%.
With our significantly improved profitability, we expect our effective tax rate for 2023 to increase to a more normal 20%. However, we do not expect to pay any significant U.S. federal cash taxes in 2023, and so cash taxes should be limited to state, local, and foreign jurisdictions. We currently expect cash taxes for 2023 to be approximately $15 million. We expect 2023 CapEx to be approximately $550 million. Most of this CapEx is for activity related maintenance and reactivation CapEx, with growth CapEx focused on high return, quick payback opportunities that we expect to be margin accretive.
Contract drilling CapEx is expected to be approximately $320 million in 2023, of which approximately $200 million is budgeted for maintenance CapEx and rig reactivations. $25 million is for customer-funded rig upgrades, and the remaining $95 million of CapEx is for items that increase incremental revenue opportunities for our existing rig fleet, including market upgrades and rental equipment, including high-margin premium drill pipe. Pressure pumping CapEx for 2023 is expected to be approximately $170 million, including $140 million of maintenance CapEx, with the remainder going to equipment upgrades and the activation of our 13th spread. Of the $140 million of maintenance CapEx, $35 million is for maintenance and support equipment, which has been underfunded in recent years.
Directional drilling CapEx for 2023 is expected to be approximately $25 million, the majority of which is for growing our fleet of next-generation mud motors and MWD systems to meet customer demand. We're also continuing our strategic shift towards higher-margin rotary steerable work with the purchase of additional rotary steerable systems. The remaining $35 million of CapEx for 2023 is for our other segment and general corporate purposes. Turning now to our balance sheet. We ended 2022 with $836 million of long-term debt after we repurchased approximately $22 million of debt in the fourth quarter. Our debt to adjusted EBITDA metric improved to 1.2 times for 2022, and on a fourth quarter 2022 annualized basis, debt to adjusted EBITDA was less than 0.9 times gross or approximately 0.7 times net of cash.
Our cash balance improved to $138 million at the end of 2022 due to improved profitability and the benefit of a large customer prepayment during the fourth quarter. This prepayment is reflected in our balance sheet as a short-term liability. As we work off the prepayment, the liability will decrease, resulting in increased working capital during the first half of 2023. I'll now turn the call back over to Andy Hendricks.
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. 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.
At this time, I would like to remind everyone in order to ask a question, press star then the number 1 on your telephone keypad. We'll pause just for a moment to compile the Q&A roster. Your first question comes from the line of Arun Jayaram from JPMorgan Chase. Your line is open.
Yeah, good morning. Andy, I was wondering if you could, you know, shed some thoughts. I know you guys did a survey, in October of 70 of your key customers, and it highlighted, you know, pretty meaningful, planned increases in the rig count. Obviously, the gas market has changed quite a bit since that time. As you do a postmortem on that, you know, what's your thoughts on demand? 'Cause it is, you know, trending lower than you thought just a few months ago. I have a follow-up on that.
Sure. No problem. Yeah, we did that survey back at the end of September, early October. You know, at that time, WTI was trading around, you know, $85 a barrel, and natural gas was certainly much higher. I think there was, you know, a little bit more enthusiasm from the E&Ps that we talked to about what their rig count was gonna do. You know, we've certainly seen some changes. The, you know, the interesting thing as we work through the year, you know, we have seen changes in the rig count, but, you know, when you look at the breakdown of AC rigs, and especially when you know, you look at what we're doing with Tier 1 super-spec rigs, you know, that market has held steady.
While we're not seeing overall growth in the rig count because you've seen SCR and mechanicals get released over the last few months, you know, the high-end market that we participate in is certainly keeping a very high utilization rate and supporting the leading-edge pricing.
Great. Just my follow-up, you know, through a decent amount of market observers, including our own, you know, we could see a 30 to 50 rig decline on the gas rig count in terms of trying to, you know, the supply response call 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?
Yeah, we're already seeing that. You know, we're already seeing where, you know, we've had 2 rigs go down in gas, we're seeing, you know, discussions and requests for rigs to go into oil markets. I think that, you know, while rigs may be coming down, we're also reactivating rigs. When you look at net-net, what we're doing and what we're seeing with customers, you know, we still expect our rig count to grow in 2023. Remember, we're not participating in the SCR mechanical market. Those types of rigs are on long-term contracts. They're easy to release.
You know, outside of, you know, the Northeast where we have a large number of rigs in gas, and those are primarily under term contracts with hedged customers, you know, there's gonna be some softness in the natural gas markets outside of that one, and we certainly recognize that. 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 thirteenth spread, just kinda 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.
We've been looking at.
What's the timeline?
Yeah. 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. You know, what's happened in the market is, you know, as we would start to slowly reactivate pumps and add more pumps to what we have in circulation across all of our spreads, you know, between active in the field and maintenance, getting ready for spread 13 and doing the calculations on that, what we've been seeing is that existing customers have been absorbing the pump supply. I believe that's happening across the industry. You know, the amount of horsepower per spread for the type of high-end work we do in places like the Delaware, you know, in the Utica, you know, we've seen E&Ps that just wanna, you know, pump at higher flow rates and higher pressures.
You know, we those are the high-end markets that we participate in in pressure pumping. So we've seen that absorb. You know, In other words, what's happening with our 13th, it's just been pushed. While we thought, you know, there might have been a chance to do it at the end of 22, we've just been absorbing our current horsepower that's been active into, you know, existing spreads. 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 23 to activate that 13th spread.
That's a late year add, it sounds like.
It'll be a late year add.
Okay. Just as a follow-up on the share repurchase side, obviously good to see you guys actually, you know, executing on the program during the fourth quarter. Curious how the plan is for that. Is that just a kind of as you generate free cash flow over and above the dividends that you'll buy it kind of, you know, periodically across the year, or is it opportunistic, or how do you see that?
I'll start, and then I'll hand it over to Andy Smith. You know, 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, you know, at those points, you know, 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.
Yeah. I don't have a lot to add to that, you know, other than to say, again, reiterate that we are committed to our return, metrics. You know, 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, you know, 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.
Yes. Good morning.
Good morning.
Andy, how many rig reactivations are embedded in the budget this year? Of those, you know, how many have contracts today, and what kind of line of sight do you have for additional contracts on the reactivations?
Right now we're planning 8 reactivations in the CapEx budget. We have line of sight on those 8. You know, we think our rig count still grows. You know, we do recognize there's some near term softness with the gas markets. I think overall we're gonna see growth through 2023.
Got it. Just circling back, you know, to Arun's question on, you know, potential, you know, downside risk on the gas side, just, you know, help us, you know, think about, you know, how do you guys, you know, if the downside case, you know, kind of materializes, you know, how do you think about, you know, 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? How do you think about kind of, you know, managing the crew count?
Just trying to get a better sense of kind of as you think about scenario analysis, kind of, you know, what's the management of the marketed fleet, you know, in more of a downside scenario?
We certainly recognize there's potential for a downside case, but I think it affects different companies differently. You know, back to the discussion of Northeast versus the other gas basins. You know, the way that our customers have been behaving and we, you know, in discussions with our customers, we believe that market remains relatively steady for us in both drilling and completions. You know, our customers are well hedged up there. The rigs are working under long-term contracts. If there's a, you know, a downside case materializing, it's likely happening outside of the Northeast, whether it's, you know, East Texas, North Louisiana, Haynesville, maybe areas of South Texas, Oklahoma, where you still have a lot of gas production. You know, with the number of rigs we have working in the Haynesville, that's only 10% of our rig count.
I think, you know, we're kind of limited, you know, in a downside case in those basins.
Got it. No, I 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 8 rig reactivations. I'm just trying to understand, right? I mean, how flexible are you gonna 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 8 rigs. I'm only doing 4 or 5," or whatever the number is, right? I'm just trying to understand the flexibility because, again, I'm looking at the stock. 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.
You know, Arun, we've always had flexibility and are available to react. You know, we're not gonna spend CapEx if it's not necessary. One thing I'll say is there is enough utilization out there to, you know, support the leading-edge pricing that we have today. I do not expect any change in leading-edge pricing. You know, I see a 2023 that we will continue to reprice rig contracts from early 2022, you know, up to the 2023 rates. You know, 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. We've got eight rig reactivations planned in our CapEx budget.
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. No, Andy, appreciate that. 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. 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. Just in general, what should we expect through the remainder of the year? How does your book reprice through the course of the year?
Yeah. I think, you know, 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. You know, we're probably gonna 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 gonna 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.
You know, that's still gonna happen because the overall, you know, utilization for Tier 1 super-spec is still high despite what's happening, you know, in recent releases of SCR and mechanical rigs. That just doesn't affect what we're doing right now. Andy, you wanna comment more on revenue per day?
On revenue per day and cost per day, you can expect revenue up about $1,500 a day and cost of about $500.
Okay. Perfect. Okay, Andy. Andy and Andy, thank you very much. I'll turn it back.
Thanks.
Your next question comes from the line of Kurt Hallead from Benchmark. Your line is open.
Hey, good morning, everybody.
Good morning.
Hey, Andy. 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, you know, these eight rigs or so. Maybe get a sense of how that cadence may play out. You know, 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 rigs, where they're gonna be more of a back-half-weighted kind of rollout?
For the activations on the rigs, they're relatively steady throughout the year. Then, as we discussed, the 13 spread's more of a Q4 event. You know, the, you know, 5 of these we announced back in September, so I don't know why this is so hard to understand. We've got 3 more on top of 5. That's not a big number. You know, we've got line of sight on this, and that's how we see this progress.
Okay, great. 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? Are they waiting on that crew to come out, or are you gonna be actively marketing it between now and then?
We're in discussions. You know, in the pressure pumping market, you know, we don't participate or try to compete in the lower end, lower pressure Midland Basin or lower pressure Marcellus. You know, our crews are set up and working the higher end, you know, higher technology, deep Utica, deep Delaware, higher pressure, higher rates in those areas. We've got a great reputation for what we do at that level of performance. You know, we've got a few customers that are looking to expand what they're doing because they're gonna be adding drilling rigs this year. Yeah, we do have some line of sight on possibilities for our crews.
Great. Last follow-up here. You mentioned repricing 30 rigs in the first half of the year. You know, what point do you think you'll have the vast majority of your rig fleet on, let's call it that $35K-$40K a day kind of leading edge?
You know, it's certainly front-end loaded in the year, but it will continue throughout 2023. 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.
Great. Thanks. Appreciate it, 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, you know, what you're seeing in between the land drilling and pressure pumping markets. You know, do you expect one to be stronger than the other in terms of 2023 profitability, ability to move rates or utilization of equipment?
I'll start with the pressure pumping. Our teams have done a really good job continuing to push pricing, you know, We have, you know, a fair amount, a good percentage of our pressure pumping that's working at that leading edge pricing. You know, 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. you know, Like I mentioned, we're gonna be repricing about 30 contracts in the first half of 2023. These are big movements on these contracts just to get, you know, 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. These adjustments are gonna happen in 2023. You know, that's why I see that, you know, 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 gonna be flat, which is not, you know, what we're projecting, we're still gonna grow margin and grow free cash flow because of the repricing.
Got it. Makes sense. 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 is about, you know, $18.3 or so in Q4. Where do you see that going for drilling? 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.
Yeah. On the drilling side, look, we're still seeing a little bit of cost creep. You know, we talked about looking in the first quarter with an increase of about $500 per day. 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. It's crept up a little bit, but pricing has stayed ahead of it. 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.
Morning, gentlemen. How are y'all?
Good morning.
Great.
Two questions from me. Number 1, you know, 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 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 progress through the year and possibly where it may end this year?
I need to kind of parse that into 2 different types of rig classes because, you know, our visibility in our drilling business is really around, you know, AC, high-spec, super-spec rigs. SCRs and mechanicals just kind of do what they do and are treated more on a spot market. The AC, high-spec, super-spec rigs primarily working on term contracts and getting repriced right now, you know, we're seeing that market to be tight, near 100% utilization today. We expect that, you know, our rig count in that sector continues to grow in 2023. You look at SCR and mechanicals, you know, those are down probably 30 rigs since the beginning of this year, but that doesn't affect what we do. You know, that's just a separate part of the market from where we participate.
It's kind of hard to predict what that part of the market's gonna do. Those aren't necessarily the types of customers we work for. You're gonna see some movement in the rig count because of what's happened in natural gas. I just don't... We don't have any visibility that that's really gonna 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, you know, increasing activity in the oil basins
Okay. Shifting gears just to the cost side and supply chain in particular, you know, 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 kinda loosen up a little bit and pricing kind of moderating some?
You know, new drill pipe, which is what we buy, you know, that's consumed in the way we do it, you know, our rigs. We buy a lot of what we call, you know, 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. When SCR mechanical rigs slow down, it doesn't change anything in the high spec drill pipe market. You know, double shoulder high torque connection drill pipe pricing has been moving up. Lead times haven't really come down. It's still, you know, around a year lead time for buying pipe. 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 gonna be affected by low-end rigs slowing down.
Anything on maybe mud pumps or any other equipment that may, you know, be duplicated on those lower quality rigs?
No. It's. You know, these are just very different systems. Ours are AC motor driven mud pumps that are not the same as what you have on an 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. Morning, guys. First one for me, nothing to do with modeling right now. The blended hydrogen project that you talked about, Andy, can you just elaborate on what exactly was involved? You know, it's kind of a long ways off, just the speed of adoption and opportunities out there. How did it go, the trial?
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 % of hydrogen, but the point was just to try to test the systems, make sure that the spark ignition engines were still gonna function properly under that type of environment. Overall, looked good. I would say that, you know, when you step back technically, huge success. You know, the next step is to try to increase the % blend of hydrogen. Overall, the economics for hydrogen, I would say today still probably present some challenges. I think that market has potential to move quickly.
It's about how do you know, procure hydrogen, how do you transport hydrogen, you know, storing it, and then putting it into the systems. I think all those things are gonna get worked out, and I think over the next year or so, we'll probably see more of an uptake there. 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 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. What type of contract duration are customers willing to entertain today versus call it 6 to 12 months ago?
We're still seeing discussions, you know, in a year or more for contracts for drilling rigs.
Okay. I mean, that kind of validates, if you will, I hate to dumb it down this way, but just the bifurcation what's going on, 'cause the way I heard all. You know, everyone's trying to get a sense for where the rig count's going, but the way you describe it seems to me you actually have this scenario where the overall rig count might bleed 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.
Okay. Yeah.
I'm doing my best to explain today. You know, the SCR mechanical rigs are gonna do what they do on the spot markets because they're not covered with term contracts, and we don't operate those rigs.
Right.
I think it's gonna affect the overall rig count 'cause, you know, it's about a quarter of the overall rig count.
Got it.
it doesn't affect, you know, drilling contractors that are running AC high spec, super-spec rigs.
Fair enough. Last one from me, and this one not to be a Debbie Downer here, but let's assume that you do see softening in a place like the Haynesville, just make up a number, 4-5 frack fleets get sort of displaced, if you will. The owners of those fleets naturally say, "Well, let's move them to an oily basin." So, you know, you look west, you go to Midland. Do you think the Permian market is tight enough where those 4-5 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?
I think there's two things that are happening in the pressure pumping market that are keeping that market tight 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, you know, is straining us and others in the industry as we try to, you know, operate more pumps into those spreads. You know, the need to have pumps cycling back to maintenance is stretched right now. You know, equipment still needs to come into our systems to efficiently operate at the, you know, higher horsepower per spread rate. That's tight, and that, you know, that's gonna absorb more horsepower.
The other is, you know, the projections of how many spreads are potentially coming out in 2023, you know, is either gonna be delayed or it's back-end loaded because the availability of equipment and engines and pumps is still tight coming from manufacturers. You know, the forecast for how many spreads are coming in, I think, you know, that gets pushed in the year. That's why I think any spreads freed up coming out of East Texas, North Louisiana are gonna, you know, that horsepower is either gonna get absorbed into the increased horsepower per spread, or it's gonna go to work in an oil basin where, you know, equipment that's planned to show up is gonna 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 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. Now, given the market churn that you're seeing, you could move those rigs, and maybe it doesn't require that level of leading edge day rate. I know you talk about utilization being tight, maybe what would be the biggest threat, in your opinion, to see any sort of softening on that 40,000 leading edge?
You know, we have a lot of discussion about that, but at the end of the day, our focus is on margin. You know, our focus and our duty to our shareholders is to maximize our margin. You know, on one side, we're gonna try to protect that leading edge day rate, and that's what we plan to do. On the other side, the demand is just still tight. We're at 100% utilization. Even if something, you know, frees up in the short term, over the long term in 2023, it's gonna get absorbed back into the system. There's no reason for us to price a Tier 1 super-spec rig at a lower day rate, knowing that eventually it's gonna go back to work at that day rate.
We just don't see any risk in 23 on that leading edge rate.
Got it. Okay. Switching over to international. Columbia, it seemed 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? 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, Just what are the overall growth prospects down there?
You know, there has been some changes in the Columbia market. We were working as, you know, six, seven rigs, and now our rig count's coming down. It's a lot of it's due to changes in, you know, the fiscal setup for the operators down there. The operators are trying to work through that and see how that's gonna affect them. We do expect our rig count to move up again in Columbia. 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.
If you would like to ask a question, press star, then the number one on your telephone keypad. Your next question comes from the line of Luke Lemoine from Piper Sandler. Your line is open.
Hey, good morning.
Good morning.
Wanted to see if you could talk a little more about the $95 million in CapEx in your drilling budget for incremental rev opportunities. Andy, you mentioned premium drill pipe, what else is in this budget? Kinda what paybacks are you getting on these investments? I guess maybe some of this is EcoCell. Could you also just kind of refresh us where you are on that initiative?
Yeah. It's, you know, Luke, it's EcoCell. It's gonna be, you know, general market upgrades, third pumps, fourth generators, things like that. Drill pipe is a big one. You know, and they're all pretty good returns. Obviously, you know, a third pump, a fourth gen, would go into, you know, potentially either 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 EcoCells, those are sort of à la carte items that pay back pretty quick, you know, inside of, you know, maybe a year and a half, 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. We appreciate the questions. Have a good day. Thank you.
This concludes today's conference call. You may now disconnect.