Patterson-UTI Energy, Inc. (PTEN) Q3 2021 Earnings Report, Transcript and Summary

Good morning. My name is Julianne and I will be your conference operator today. At this time, I’d like to welcome everyone to Patterson-UTI Energy Third Quarter 2021 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. Mike Drickamer, Vice President of Investor Relations. You may begin your conference.

Thank you, Julianne. 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 and nine months ended September 30, 2021. 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 welcome to Patterson-UTI’s third quarter conference call. We are pleased that you can join us today. This is an exciting time for Patterson-UTI and the industry in general as we expect robust demand for drilling and completions into 2022. In this rising market, we completed the acquisition of Pioneer Energy Services on October 1, which added 25 drilling rigs to our fleet, including 17 in the U.S. These rigs enhance our position as a leading provider of contract drilling services in the U.S. and expand our footprint into Latin America. We’re excited about this acquisition and welcome the Pioneer employees to the Patterson-UTI family. Next, I’m also excited to state that the market for the most capable rigs in the U.S. is officially tight. For example, we are simply sold out of XK and PK rigs in the Permian. As a result, we have seen leading edge day rates take a move up over the last month and I expect this trend to continue. It’s been a few years since we’ve had this level of utilization and increasing leading edge rates. Turning now to the third quarter, I’m very pleased with our consolidated results which benefited from higher activity and better pricing as total adjusted EBITDA increased by 44% to $51 million on a 23% increase in the revenues. In contract drilling demand for drilling rigs in the fourth quarter and into 2022 continues to be robust. For example, we have a total of 46 APEX XK and PK class rigs in the Permian Basin of which 41 are currently working. Of the remaining five rigs, four are already committed to return to work. We are effectively sold out of these rigs in the Permian Basin. Demand also remains strong for rig-based technologies that help our customers meet their goals of reducing emissions. These technologies include natural gas fueled engines, highline utility power and our EcoCell, lithium battery, hybrid energy management system. EcoCell, which uses stored energy to provide power to the rig when needed, has demonstrated the capability to reduce rig fuel consumption by more than 20% thereby reducing both fuel costs and emissions. I’d like to take a moment to command our people in both the drilling segment and our electrical engineering and control segment current power. We were recently awarded a meritorious award for engineering innovation for the EcoCell. We currently have six EcoCell units deployed and driven by strong customer demand. We are ramping our production capacity to increase the size of our EcoCell fleet. I’m proud of the work that we are doing to help our customers achieve their goals of emissions reductions. With the growth in rig demand we’ve seen, we’ve activated 32 rigs this year. While restocking and recurring these rigs has been challenging, our team has managed it very well. For the past year, the cost of reactivate a rig has been approximately $0.5 million. But with the impact that general oilfield inflation has had on supply costs the need to increase inventory levels of consumables and the impact of the tight labor market on wages. The cost to reactivate a rig is increasing. Also to help address labor challenges, we initiated a wage increase for rig-based employees in September to retain our highly skilled and efficient crews and also to attract new employees to the industry to support further increases in the rig count. It’s unusual to have to increase wages this early in the recovery but it’s also very indicative of the overall U.S. labor market conditions. With the increasing market tightness for premium equipment, we expect day rates to continue to move higher and more than offset cost inflation. In pressure pumping our business continues to improve. During the third quarter, we were able to achieve better pricing based on our outstanding service quality. We also benefited from a higher level of simul frac work and the full core impact of two spreads that were reactivated during the second quarter. Pressure pumping adjusted EBITDA more than doubled 36% increase in the revenues. During the third quarter we introduced our first EcoPlus spread, which is a Tier 4 technology spread designed to optimize natural gas substitution up to 85%. With strong demand for lower emissions technologies and consistent with our disciplined approach to capital spending, we plan to continue to upgrade engines on existing pump trailers to dual fuel. Late in the fourth quarter, we plan to add our 11th spread. In the first quarter we expect to add our 12th spread, which will be another EcoPlus spread. With the activation of our 12 spread in the first quarter over half of our active spreads will be dual fuel capable. In Directional Drilling demand for our impact, directional drilling motors and Mercury measurements while drilling system remains strong. During the third quarter, we benefited from the full quarter impact of the growth and the activity we saw in the second quarter. With a strong growth and activity we’ve seen this year delays and receiving order equipment, we are effectively sold out of equipment at the moment. We have orders in place for the components necessary to expand our fleet of motors and MW kits, but it seems to be common across the entire economy, supply chains are stretched and it just is taking longer for things to be delivered. While waiting for additional components to further increase activity, we will continue to focus on improving pricing. Before I turn the call over to Andy Smith, I would like to discuss our recent announcement to collaborate with Corva on data analytics and visualization across all of our businesses. Corva is a leading provider of real time drilling and completions analytics has become the go to for operators to collect, analyze and visualize data across all the contractors that they use. We expect this collaboration will leverage our advanced well site and cloud-based data capabilities and give our customers more options, including, combining our capabilities with Corva’s extensive suite of more than 100 drilling and completions apps. Utilizing data from our CORTEX key edge server available from the well site, we plan to work with Corva to further develop solutions to help operators drill more productive and profitable wells while hitting lower emissions targets. One such solution is the ability for Corva to display the P-10 Plus power management page, which is a real time application that allows operators to remotely monitor fuel consumption and emissions. We have successfully completed initial test with this app and expect it will soon be deployable to customers. We were pleased to collaborate with Corva as they share a similar view as to the incredible potential made possible through the use of advanced data analytics in the drilling and completion businesses. With that, I will now turn the call over to Andy Smith who will review the financial results for the third quarter.

Thanks, Andy and good morning. For the third quarter we reported a net loss of $83 million or $0.44 per share. Consolidated adjusted EBITDA increased to $51.1 million. Within our segments in contract drilling, our average rig count improved to 80 rigs from 73 in the second quarter. This increase in the rig count drove an 11% increase in total contract drilling revenues and gross margin. On a per day basis, the average rig margin during the third quarter increased slightly to $6,300. As an increase in average revenue per rig day was largely offset by a similar increase in average cost per day. At September 30, 2021, Patterson had term contracts for drilling rigs in the U.S. providing for approximately $286 million of future day rate drilling revenue and Pioneer had another $64 million. Based on contracts currently in place in the U.S. and including the rigs from Pioneer, we expect an average of 53 rigs operating under term contracts during the fourth quarter and an average of 35 rigs operating under term contracts during the four quarters ending September 30, 2022. For the fourth quarter, we expect activity growth will be robust. On a Patterson-UTI standalone basis, our average rig count is expected to increase by 13 rigs quarter-over -quarter to 93 rigs in the fourth quarter. The U.S. rigs of Pioneer are expected to contribute another 13 active rigs to our average rig count bringing our total expected average rig count in the U.S. to 106 rigs for the fourth quarter. General oilfield inflation including the cost of labor continued to be a challenge. In September, we initiated a wage increase for rig-based employees, which is expected to increase our average cost per rig day by approximately $600 per day. We expect to ultimately recover this expense from customers in the form of higher day rates. Additionally, we also expect a further increase in rig reactivation expenses during the fourth quarter, due to both a larger number of rig reactivations to support the expected growth in our rig count and the rising cost of rig reactivations. In addition to higher labor expenses for the rig reactivations, the cost of restock the rigs have increased. The growth of the rig count is expected to lead to revenue growth in the fourth quarter. On a per day basis, the revenue benefit from the pass-through of higher wages is expected to be largely offset by various items. Despite recent strength and leading edge day rates many of the rigs being activated were contracted in late summer and in some of the weaker regions where day rates have not been as strong. In the near term, we also expect lower ancillary revenue on a per rig basis, as we look to replenish our available inventory of ancillary parts and equipment. Additionally, the integration of the Pioneer rigs into our fleet has a negative impact on our average daily revenue. Therefore, the result is that we expect average revenue per rig day in the U.S. to increase slightly in the fourth quarter to approximately $21,600. With the increased costs for labor and rig reactivations, we expect the average rig operating costs per day in the U.S. to increase to $16,100 per day. I want to emphasize that we did not see this fourth quarter level of cost per day in the U.S. as the new normal. Our estimate of fourth quarter costs in the U.S. include approximately $900 per day of rig reactivation costs, which should come back out of our costs when the pace of rig reactivation slows. Internationally, we expect the Pioneer rigs in Colombia will generate approximately $15 million of revenue in the fourth quarter with approximately $4 million in gross profit. In pressure pumping during the third quarter, we’ve benefited from better pricing, more simul frac work and the full quarter impact of two spreads that were reactivated during the second quarter. Pressure pumping adjusted EBITDA for the third quarter more than doubled from the second quarter to $16.1 million, while pressure pumping revenues increased by 36% to $153 million. For the fourth quarter despite expecting lower utilization due to the holidays and potential weather delays, pressure pumping revenue is expected to increase to approximately $167 million, while pressure pumping gross margin is expected to increase to approximately $18.5 million. Turning now to Directional Drilling, gross profit for the third quarter increased 35% to $3.4 million, as revenues increased 28% to $31.7 million. For the fourth quarter, we expect revenues to increase to approximately $32.5 million with a gross profit of approximately $4.5 million. Revenues and our other operations which includes our rental technology and E&P businesses improved a $15.6 million and gross margin improved to $5.2 million in the third quarter. For the fourth quarter we expect both revenues and gross profit to be similar to third quarter levels. Before I turn the call back to Andy, let me touch briefly on the acquisition of Pioneer Energy Services. We completed this acquisition on October 1, and therefore we expect a full quarter contribution from Pioneer during the fourth quarter. We have begun the process to divest the production services business and as such we expect to report these segments as discontinued operations going forward. On a consolidated basis, including the impact from Pioneer for the fourth quarter we expect total depreciation depletion, amortization and impairment expense of approximately $145 million. Selling, general and administrative expenses are expected to be approximately $24 million for the fourth quarter. For the full year 2021,we expect an effective tax rate of approximately 17%.Including the shares issued as part of the Pioneer acquisition, we expect the fourth quarter average share count to be approximately 216 million shares. We are maintaining our expectation for capital spending with CapEx of $165 million for the year, but with supply chain disruptions we may not spend all of this amount in 2021. Also, we will be paying a quarterly cash dividend of $0.02 per share on December 16, 2021 to holders of record as of December 2, 2021. With that I’ll now turn the call back over to Andy Hendricks.

Thanks, Andy. As I previously mentioned, it’s a very exciting time for the industry and for Patterson-UTI given the increasing demand for services. This demand increase is based on both discussions with our customers regarding their drilling and completions plans and also looking at the global oil supply demand macro over the next year. As well E&Ps are looking to reduce emissions and Patterson-UTI has a leadership position and a number of technologies to help achieve this. Let’s start with a macro. We have crude stocks being drawn down around the world and U.S. inventories are below the five-year average. Demand for oil is forecasted by IA to rise while OPECplushas stated they will hold to their previously announced increase for the combined groups’ production. In the U.S., our industry rig count is only around 540 rigs today and while some activity demand projections show that it could go to 650 rigs to 700 rigs in 2022. This still may not be sufficient to fully offset petroleum demand growth. So we could have turned oil prices for a while and the associated rig activity demand that goes along with that. For Patterson-UTI based on conversations with customers, we expect strong growth in drilling activity in the fourth quarter and these conversations suggest this robust growth and activity will continue into 2022 even while public E&P show capital discipline and return cash to shareholders. However, even with the activity increases that we’ve seen over the last couple of months, it’s interesting to note that these increases are largely based on WTI trading around $70 a barrel. And it’s only in the last few weeks we’ve had inquiries for rigs based on WTI at $75. So we’ve yet to enter any meaningful discussions regarding an increase in activity based on where we are today with WTI around $80. Additionally, public operators will soon be setting their 2022 budgets with a higher price deck. Based on all this I believe that if all remains above $70 and right now there is no underlying forecasted increase in supply that says otherwise, we will see increasing activity due both to higher commodity prices and the higher E&P CapEx budgets in 2022. All that being said, how much growth the industry ultimately sees in drilling completion activity in ‘22 will largely be a function of pricing for these services versus the cost to activate and staff the equipment. Based on the current economics reactivation, we believe that across the industry, the availability of equipment that can be economically reactivated at current pricing has nearly exhausted. This relative tightness is driving price increases for our services. And while we have seen cost increases, we have also seen recent leading edge price increases over the last couple of months. And we believe that further pricing increases are attainable going forward, meaning we expect to see net price increases with improving margins in 2022. Overall, we are very encouraged by the macro, by the conversations we are having today with our customers by the uptake of technologies to reduce emissions such as EcoCell and especially by the increasing demand and pricing for our services into 2022. With that, we’d like to thank all the employees for their hard work efforts and successes. Julianne we’d now like to open the call to questions.

[Operator Instructions] And our first question comes from Ian Macpherson from Piper Sandler. Please go ahead, your line is open.

Thanks, good morning. Andy, I appreciate your opening proclamation that we are officially tight. And I wanted to follow up on that. It looks like you’re even excluding Pioneer that you’re outpacing the industry rig adds here in Q4. But if you’re running in the low 100s, I have you at around 160 plus total “super-specs” in-house but you say that the available spare inventory in the industry is not necessarily economic to reactivate at current pricing. Can you bridge that for me a little bit in terms of what kind of day rates you would like or you would require in order for Patterson to bring another call your next couple of dozen reactivations out next year and what those would cost and what kind of further day rate increases would enable that?

Yes, good morning. So we’re really excited about the demand we’re seeing and also about the leading edge price moving upwards, we’ve seen over the last month or so. And when you look at the rig market and like I said, we’re essentially sold out of the XK and PK APEX in West Texas and the Permian right now. And so when you look at the market and we do the analysis on what we’re trying to get pricing has to move up and that’s why it’s been moving up. So there’s the cost to reactivate the rigs, which has moved up because we’ve been through a big downturn we’ve to put consumables back on the rigs. And we’ve done a wage increase for the people in the field on the drilling rigs. And so when you combine all that in that’s going to move our OpEx per day up, and so we have to get better pricing. So like I said, we’re very excited about what we’re seeing, that leads us to believe that it’s not a problem to get those levels of pricing to be able to put those rigs back to work. And so, I expect our activity to continue to increase. But when I say the market is tight, I’m talking about what we consider the most capable rigs in the U.S., the newest rigs built that we were still building in 2014 and early 2015, those rigs that were fully kidded out back in those years are essentially sold out.

And I think that you said that you have a lot of reactivations coming in Q4, but reflective more of summer pricing than of today’s pricing, which has moved quite a bit. So if we think about rolling-off your 900 bucks a day of reactivation costs in Q4 and you’re going to continue to melt up towards leading edge from Q4 into the first half, it seems like normalized margins with those adjustments for the first half could easily be between $7,000 and $8,000 a day, would you take exception with that math?

No that kind of falls in line the way we look at it. Of course, we’re going to be operating a large number of rigs as we go into 2022. And it takes some time for everything to move up, but the leading edge is definitely moving up.

Can I squeeze in one more? Can you can you tell me for your Colombia guidance what that utilization implies for Colombia? And if there’s any upside to that those numbers of the near-term if you see that more steady state until you digest and integrate a little bit in that new market?

Yes for us, we’re really excited about the operations and the potential in Colombia. That’s a great team that business has been running for 14 years down there, they’re well respected by the customers. And being a part of Patterson-UTI, it gives them a lot of upside and a lot of potential. And so, we see the potential for growth down there over the next year. And we’ll put capital into that business where it makes sense. But given today’s market in today’s oil prices, we think that’ll happen. So we do see growth potential down there. But we will be careful about how we’re calling it that out that markets not near the size of the U.S. And so we don’t want to price signal by giving too much information to the public domain.

Fair enough. Thanks, Andy.

Your next question comes from Connor Lynagh from Morgan Stanley. Please go ahead, your line is open.

Yes, thanks. Appreciate all the context on the cost items. And I wanted to hone in on the labor side of things. Obviously, wages in the oilfield have been under pressure for some time now. I’m curious at this point with some of the other industries that you compete with for labor, do you offer a competitive wage? Do you offer a premium wage? Basically, the question is driving to how hard is it to attract talent? And do you feel that you’re going to need to raise prices again, if and when activity continues to improve?

So when you look at how we’ve treated the wages for the people on the drilling rigs and we’ll talk about the drilling rigs, that’s the largest business we have, of course. We went through a big downturn after ‘14 and to ‘15 and ‘16, we didn’t reduce the wages on the drilling rigs. And so we’ve kept the wages steady. And this is actually the first increase that we’ve been able to give and the market is driving that. But we offer a very competitive wage and it’s not just about the hourly, but when you look at the amount of overtime, when an individual gets when there are two-week hitch on the drilling rig. These are very competitive wages in the market and with the wage increase, very competitive versus other industries, whether it’s trucking or working in warehouses or construction or Home Depot. So we’re very comfortable with where we’re at today. I do not see us having to raise wages in the field anytime in the foreseeable future right now, because I do believe we’re very competitive where we are, where we put them.

Got it. Maybe just another sort of costs related question. More on the pressure pumping side of things. Basically what I’m wondering is, as we look at incremental reactivations I mean, it seems that your actions would indicate that pricing is sufficient to support the economics of this reactivations. I guess the question is twofold. A) Do you need further pricing to justify more or there’s this question of the demand being there? And B) how much would it cost do you have substantial upgrades and deferred maintenance that needs to occur to do that?

Yes, this is similar to say 2016,’17, ‘18, as we came out of that, the early spreads that you activate are always the easiest and the most cost effective to activate and it similar with us this time, and probably similar to a lot of our peers in the sector. When you’re activating those early spreads, you’re in that $2 million to $3 million range. And then as you work into spreads in your overall fleet, it’s going to cost you more. So there’s the activation costs, there’s also the cost in some cases on some spreads where we’re swapping engines on trailers. And so we consider the reactivation cost and the cost to swap engines on trailers for the newer technology. And we consider all that when we’re looking at the pricing for the job. So not just the reactivation, but in some cases, also the engine swaps as well. We think, absolutely the pricing is there today, for what we’re doing in terms of reactivation, as we get into 2022 sure that the cost to activate a spread on just the reactivation cost alone is going to move up a little bit more. But I do think that the markets going to support the pricing, I think that this is across the board or across the industry, we’re all looking at the same challenge. And along with the labor shortages that we’re seeing where we’re having to spend more money and work harder to recruit people and train people, this is what’s going to drive the price increases. So we do see increasing more spreads in 2022, we’re going to have that level of demand given where commodity prices are likely to trade. So I’m not concerned at all about that pricing is going to go up.

Alright, thanks very much.

Your next question comes from Keith Mackey from RBC Capital Markets. Please go ahead, your line is open.

Good morning, and thanks for taking my questions. I just wanted to start up by asking as you talk about simul frac in the release and in the prepared remarks. Just curious how much of that work you’re doing right now? And can you just kind of run through maybe the margin accretion that you get from a simul frac job versus a standard frac?

So we do simul frac in both the Northeast and in the Permian Basin, and it can vary within the quarter. So we can have a situation where we’re on two simul frac jobs at the same time, between the Northeast and Texas or New Mexico or that we’re only on one. So it’s really hard to quantify within the quarter, it’d be really difficult for me to give you anything that helps you understand that from a modeling standpoint. But it does vary, but it keeps us competitive. And it’s one of the reasons that our pricing is moving up. And it’s one of the reasons that we’re able to activate more spreads. But it’s hard for me to give you some numbers that would help you understand within the quarter how that that looks within our numbers.

Understood. And just curious now about the pressure pumping market and consolidation. And you mentioned that, you expect pricing to be supportive just based on increasing levels of demand. But do you think that there’s consolidation or attrition needed to help support pricing even further? And do you see much more of this happening or will it be just more natural attrition that helps, kind of balance the market as well?

Look, we’re always happy when we see consolidation with any of the markets that we compete in that’s always supportive for the market and supportive for pricing. But frankly, going into 2022, we don’t have to have any more consolidation for pricing to go up. That’s not something that has to happen. Pricings going to go up because of the demand because of the tightness that’s in the market today. If we get more consolidation in the market, that’s great, but it’s certainly not necessary.

Got it. Thanks very much.

Your next question comes from Waqar Syed from ATB Capital Markets. Please go ahead, your line is open.

Thank you. Andy what’s the horsepower that will be associated with the 12 crews that you’re going to have active in Q1?

Well, Waqar thanks for asking me that question this morning. Given that sometimes we’re on simul frac jobs and sometimes we’re not it really varies. And this is across the Northeast Texas and in Texas, it’s Permian, South Texas. So everything varies. I’d have to get back to you on that with a number.

Would it like55,000 per crew, just like on average be a reasonable number?

I’m looking at my team over here, it’s going to be plus or minus in that range until a little bit more when we’re running simul frac jobs. And that 55 is not everything that would be on location because you’ve got rotation of equipment back to the shop or maintenance.

Fair enough. And then Andy, you mentioned about price increases in drilling, let’s take that first, could you maybe talk about the magnitude of increases that have happened and what magnitude of increases you expect going forward?

So, we don’t normally call out a number. But I’m going to call out a number today because we’re not going to put out any rigs unless the base price for the rig is in the low 20s. That’s where we are. And that’s a significant step up from where we were a year ago or even in the summertime. And that doesn’t include any of the ancillary equipment that we might put on a rig, drill pipe, other equipment, other services, we may provide, associated with contract drilling, which drives that total price into the mid 20s. So that’s a big step up and really exciting that leading edge is now at that level in the low 20s.

Is the spot rate and your contracted rate now in line or spot has exceeded a contracted rate?

Yes, spot and leading edge is above the contracted rate because we’ve been signing agreements over the last year and a half. And even in this quarter and going into the fourth, we have some contracts that were signed pre-COVID that are starting to roll-off. So, we have a variety of levels of pricing in that tower of contracts that we have, but leading edge is moving up quickly. So it’s above where the average contract and prices.

And then, just shifting to the pumping side, any comments in the magnitude of price increases there especially on the net-net price increases?

I’m going to call out our pumping team for doing a great job over the last few quarters, they manage, they held of a downturn and stayed cash neutral during the COVID downturn. And then here in ‘21, they’ve provided excellent service quality out in the field of being careful about how they’ve spent dollars whether it’s on OpEx or CapEx and it’s really paying-off and showing the average, adjusted EBITDA has been moving up nicely. And so all that combined, when you look at the service quality providing the new technology that we’re putting out for some of the customers that helps push pricing, it’s definitely in the double-digit percentile movement upward quarter-on-quarter. I know that doesn’t mean much to say double-digit percentile, but suffice it to say that we’re pleased with the number.

Just one final question, if I may, your EBITDA per crew was around $6 million and right number in Q3, which is a decent when you compare it to the peers. But where do you think it could be like a year from now?

I think we’re going to be back up into numbers that reflect, what I would say 2018, even early ‘19, before we started slowing activity in 2019. So, I think there’s still a lot of room for that to move, because we see a lot of demand potential out there based on where commodity prices are, whether it’s oil or natural gas and we see a lot of upside.

Thank you, Andy. Appreciate the answer.

Your next question comes from Vaibhav Vaishnav from Coker & Palmer. Please go ahead, your line is open.

Good morning, guys. Thank you for taking my questions.

Good morning.

Good morning. Is there a way you can help us just think about, if you think about the pressure pumping capacity you have in terms of fleet, how many more are there on the sidelines? And then how should we think about CapEx required to get them back?

So, we have around 1.6 million horsepower in total, well 1.3 million, when you talk about the frac horsepower. And when you look at where we are today and where we’ll be running up to 12 spreads, which we have visibility on now. We still got a ways to go. And like I mentioned earlier as you work into the existing equipment, the stack right now share, your CapEx and OpEx starts to move up in order to redeploy that equipment. But we still have a ways to go. We were running as many as 25 frac spreads just a couple years ago. So we still have all that inventory. Well, have all that equipment and inventory, it’s just a matter of looking at the economics, which we do on a project-by-project and case-by-case basis to determine if we think it’s economically feasible to reactivate.

Got it. So you have another 10, at least 10 more fleets to go, okay, that’s helpful. Going to drilling actually, just think about inflation is increasing, you are talking about day rates increasing? Is there a way you can talk about when can we see the margins that we saw in 3Q? Is it more like the first half 2022 scenario? Is it more second half 2022 scenario?

It’s the first quarter 2022 scenario. We expect in the first quarter of ‘22 to rebound in the ballpark of where we were in Q3 of this year.

Got it. And if I may squeeze in one more, can you talk about demand and availability of 5.5 inch drill pipe, just like I was hearing some anecdotally that E&Ps are more willing to pay higher for 5.5 inch drill pipe and it is already sold out?

Yes, so 5.5 inch drill pipes in very short supply and historically that was an offshore size and now we’re using it in the U.S. onshore market. That market has tightened up, we own a significant amount of 5.5, which allows us to push pricing on the inventory that we have. We have 5.5 on order and we’re hoping that the mills and the suppliers can keep up. The mills are also having to shift to produce more casing for the E&Ps at the same time. So we’ll just start to see how our deliveries go. But we’ve been placing orders throughout this year for deliveries that we’ll get in the next year.

That’s very helpful. Thank you for taking my questions.

[Operator Instructions]. Your next question comes from Ian Macpherson from Piper Sandler. Please go ahead, your line is open.

Thanks very much for giving me a follow up. I just wanted to see two things. Are you hoping or expecting to close the well service divestiture by year-end? And then also I was going to ask if you have any framework for CapEx for 2022, whether it’s a range of numbers or just a ratable framework for activity?

Yes, this is Andy Smith. We were engaged in a process right now on the sale of the production services business. I don’t really have a great estimate for when that will complete. But we are working actively currently. And within the next quarter or the quarter after that, I can’t tell you exactly where it falls. On CapEx, it’s too soon for us to give you that number. We’re going to look at it throughout the next few months as we’re doing our budget process and we’ll give you that on the fourth quarter call.

We have no further questions in queue. I would like to turn the call over to Andy Hendricks for closing remarks.

Thanks, Julianne. Well, I’ll say once again, we’re really excited about what’s happening in the business and the demand and pricing increases we’re seeing going into 2022 and excited for the potential, for this business next year. So thanks to all the Patterson-UTI team for everything that they’re doing and thanks for those of you that joined us on the call today. Thanks.

Ladies and gentlemen, this concludes today’s conference call. Thank you for your participation, you may now disconnect.