Earnings Call Transcript - PTEN Q3 2021

Operator, Operator

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. Thank you. Mike Drickamer, Vice President of Investor Relations. You may begin your conference.

James Drickamer, Vice President of Investor Relations

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?

Andy Hendricks, CEO

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 increase 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 commend 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 reactivating these rigs has been challenging, our team has managed it very well. For the past year, the cost of reactivating 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, with a 36% increase in 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 strong growth and activity we’ve seen this year, delays in receiving order equipment have led us to be 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 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 that has become the go-to for operators to collect, analyze and visualize data across all of 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 tests 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.

Andrew Smith, CFO

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 restocking the rigs has 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 in 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. includes 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 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 include our rental technology and E&P businesses improved to $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 to Andy Hendricks.

Andy Hendricks, CEO

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 and 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 perspective. 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 the IEA to rise, while OPEC Plus has stated they will hold to their previously announced increase for the combined group’s 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 see tight oil prices for a while and the associated rig activity demand that comes 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 that this robust growth in activity will continue into 2022, even while public E&P companies 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 that 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 oil prices remain above $70 and right now there is no underlying forecasted increase in supply that says otherwise, we will see increasing activity due to both 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 and completion activity in 2022 will largely be a function of pricing for these services versus the cost to activate and staff the equipment. Based on the current economics of 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. 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 macroeconomic conditions, by the conversations we are having 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 and efforts and successes. Julianne, we’d now like to open the call to questions.

Operator, Operator

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

Ian Macpherson, Analyst

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?

Andy Hendricks, CEO

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. When you look at the rig market, we’re essentially sold out of the XK and PK APEX in West Texas and the Permian right now. So when you look at the market, 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. The cost to reactivate the rigs has moved up because we’ve been through a significant downturn and we’ve had to put consumables back on the rigs. We've also implemented a wage increase for personnel on the drilling rigs. When you combine all that, that’s going to move our OpEx per day up, and so we have to get better pricing. We’re very excited about what we’re seeing, and 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. 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 producing in 2014 and early 2015 are essentially sold out.

Ian Macpherson, Analyst

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 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?

Andy Hendricks, CEO

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

Ian Macpherson, Analyst

Can I squeeze in one more? 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?

Andy Hendricks, CEO

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 and they’re well respected by the customers. Being a part of Patterson-UTI gives them a lot of upside and potential. We see the potential for growth there over the next year. We’ll put capital into that business where it makes sense. Given today’s market and today’s oil prices, we think that will happen. We do see growth potential there. However, we will be careful about how we call that, as that market is not near the size of the U.S. We don’t want to signal too much to the public domain.

Connor Lynagh, Analyst

Yes, thanks. Appreciate all the context on the cost items. 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?

Andy Hendricks, CEO

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 significant downturn after '14 and into '15 and '16, we didn’t reduce wages on the drilling rigs. So we’ve kept those wages steady, and this is actually the first increase we’ve been able to give, and the market is driving that. We offer a very competitive wage and it’s not just about the hourly rate; when you look at the amount of overtime an individual get when there are two-week hitches on the drilling rig, these are very competitive wages in the market. With the recent wage increase, we remain very competitive compared to other industries such as trucking or warehouse work. So we’re comfortable with our current wage structure and do not foresee a need to raise wages in the field anytime soon due to our competitive positioning.

Connor Lynagh, Analyst

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

Andy Hendricks, CEO

Yes, this is similar to say '16, '17, '18, as we came out of that downturn—the early spreads you activate are always the easiest and most cost-effective to activate. That’s similar with us this time and likely similar to a lot of our peers in the sector. When you activate the early spreads, you’re in that $2 million to $3 million range. As you work into spreads in your overall fleet, it’s going to cost more. There’s also the cost of some spreads where we’re swapping engines on trailers. We consider both the reactivation costs and the cost to swap engines on trailers for the newer technology. We do think 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 market will support the pricing. Across the industry, we’re all seeing the same challenges. Along with the labor shortages we're facing, we're having to spend more money and work harder to recruit and train people, but this is going to drive the price increases. We do see increasing activity in 2022, driven by the demand based on commodity prices.

Keith Mackey, Analyst

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? Also, can you run through maybe the margin accretion that you get from a simul frac job versus a standard frac?

Andy Hendricks, CEO

We do simul frac in both the Northeast and in the Permian Basin, and it can vary within the quarter. We might have a situation where we’re on two simul frac jobs at the same time, between the Northeast and Texas or New Mexico or we might only be on one. So it’s really hard to quantify within the quarter; it’s difficult for me to provide specific numbers to help you understand that from a modeling standpoint. But it does vary, and it’s one of the reasons that our pricing is moving up. It’s contributing to our ability to activate more spreads.

Keith Mackey, Analyst

Understood. Just curious now about the pressure pumping market and consolidation. 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? 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?

Andy Hendricks, CEO

Look, we’re always happy when we see consolidation in any of the markets that we compete in; that’s always supportive for the market and pricing. But frankly, going into 2022, we don’t have to have any more consolidation for pricing to go up. That’s not a necessary condition. Pricing will increase due to demand and the tightness in the market today. If we see more consolidation, that’s great, but it’s not required.

Waqar Syed, Analyst

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

Andy Hendricks, CEO

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. I’d have to get back to you on that with a specific number.

Waqar Syed, Analyst

Would it be around 55,000 per crew, just like on average be a reasonable number?

Andy Hendricks, CEO

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. That 55 is not everything that would be on location because you’ve got rotation of equipment back to the shop or maintenance.

Waqar Syed, Analyst

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

Andy Hendricks, CEO

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 $20,000 range. That’s where we are, which is a significant step up from where we were a year ago or even in the summertime. That doesn’t include any of the ancillary equipment that we might put on a rig, drill pipe, or other equipment or services we provide, which drives that total price into the mid $20,000s. So, that’s a big step up, and it’s really exciting to see that leading edge at that level in the low $20,000s.

Waqar Syed, Analyst

Is the spot rate and your contracted rate now in line, or is the spot rate exceeding the contracted rate?

Andy Hendricks, CEO

Yes, the spot rates and leading edge are above the contracted rate because we’ve been signing agreements over the last year and a half. 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 the tower of contracts that we have, but leading edge is moving up quickly, so it’s above where the average contract prices are.

Waqar Syed, Analyst

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

Andy Hendricks, CEO

I’m going to call out our pumping team for doing a great job over the last few quarters. They managed to hold off a downturn and stayed cash neutral during the COVID downturn. Now in 2021, they’ve provided excellent service quality in the field while being careful with expenditures on OpEx and CapEx, and this is really paying off with average adjusted EBITDA moving up nicely. Pricing is definitely in the double-digit percentile movement upward quarter-on-quarter. I know that’s vague, but we’re pleased with those numbers.

Waqar Syed, Analyst

Just one final question, if I may. Your EBITDA per crew was around $6 million in Q3, which is decent compared to peers. Where do you think it could be like a year from now?

Andy Hendricks, CEO

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

Vaibhav Vaishnav, Analyst

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

Andy Hendricks, CEO

Good morning.

Vaibhav Vaishnav, Analyst

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? Then how should we think about CapEx required to get them back?

Andy Hendricks, CEO

So, we have around 1.6 million horsepower in total, well, 1.3 million when you talk about the frac horsepower. 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 have a ways to go. Like I mentioned earlier, as you work into the existing equipment, the stack right now is that your CapEx and OpEx start 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 of years ago. We still have all that inventory and equipment; it’s just a matter of looking at the economics on a project-by-project and case-by-case basis to determine if we think it’s economically feasible to reactivate.

Vaibhav Vaishnav, Analyst

Got it. So you have at least 10 more fleets to go, okay, that’s helpful. Going to drilling, actually just think about inflation increasing. You were talking about day rates increasing? Can you discuss when we might see the margins that we saw in Q3? Does that seem more like a first half 2022 scenario, or is it more like a second half 2022 scenario?

Andy Hendricks, CEO

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.

Vaibhav Vaishnav, Analyst

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

Andy Hendricks, CEO

Yes, the 5.5 inch drill pipe is in very short supply; historically that was an offshore size, but 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 hope that the mills and 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 begin to see how our deliveries go. We’ve been placing orders throughout this year for deliveries that we’ll get in the next year.

Ian Macpherson, Analyst

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? Also, do you have any framework for CapEx for 2022, whether it’s a range of numbers or just a ratable framework for activity?

Andrew Smith, CFO

Yes, this is Andy Smith. We are engaged in a process right now on the sale of the production services business. I don’t have a great estimate for when that will complete, but we are actively working on it. Within the next quarter or the quarter after that, I can’t tell you exactly when 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 provide that information on the fourth quarter call.

Operator, Operator

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

Andy Hendricks, CEO

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. We’re excited about the potential for this business next year. Thanks to all the Patterson-UTI team for everything they’re doing, and thanks for those of you that joined us on the call today. Thanks.

Operator, Operator

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