Patterson Uti Energy Inc Q1 FY2023 Earnings Call

Thank you for waiting. I would like to welcome everyone to the Patterson-UTI Energy First Quarter 2023 Earnings Conference Call. Mike Drickamer, Vice President of Investor Relations, will now begin the conference.

Thank you, Cheryl. Good morning. And on behalf of Patterson-UTI Energy, I'd like to welcome you to today's conference call to discuss results for the 3 months ended March 31, 2023. Participating in today's call will be Andy Hendricks, Chief Executive Officer; and Andy Smith, Chief Financial Officer. A quick reminder as 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. And now it's my pleasure to turn the call over to Andy Hendricks for some opening remarks. Andy?

Thanks, Mike. Good morning, and thank you for joining us today for Patterson-UTI's first quarter conference call. We are pleased to report another quarter of solid financial results. The exceptional results in our contract drilling segment demonstrate our ongoing ability to capitalize on the robust demand for Tier 1 super-spec rigs and the renewal of drilling rig contracts at current rates. During the first quarter, we continued to return capital to shareholders and strengthen our balance sheet at the same time. We repurchased 5.6 million shares of our common stock for $73.6 million, and we repurchased $9 million of long-term indebtedness for only $7.8 million. Our pace of share repurchases accelerated as we believe the price of our shares are disconnected from the underlying fundamentals of our business and represent an outstanding opportunity. Softness in natural gas prices, along with uncertainty regarding the future trajectory of oil prices has led to what we believe to be a transitory and mid-cycle pause in activity. However, we expect relative stability in the rig count for Tier 1 super-spec rigs as operator budgets closely align with current crude oil prices due to capital discipline and current crude oil prices continue to support ongoing drilling and completion activity. The decline in the overall rig count to date during the first quarter has been both nuanced and bifurcated. Lower-spec SCR and mechanical rigs were primarily released and the net result was the high grading of the overall industry rig fleet, driven by various operators. This high grading, which positively impacts well economics has supported demand across the industry for Tier 1 super-spec rigs and maintained a high level of utilization. Looking forward, we expect that improving market fundamentals for oil will positively impact drilling activity levels, although near-term drilling and completion activity may be modestly affected by current natural gas prices. In contract drilling, we will continue to capitalize on our position as a leading provider of Tier 1 super-spec rigs and will strategically focus on profitability and cash flow over activity levels. We are confident we can best help our customers improve their drilling economics through our continued focus on operational excellence. By focusing on the efficiency gains offered by Tier 1 super-spec rigs and integrating our latest technology solutions, we help our customers improve their well economics. We anticipate the current natural gas prices will cause a small reduction in our rig count in the near term. However, the continued repricing of below market rates from contracts signed in previous years to current rates upon contract renewal this quarter is expected to lead to increased margins and increased overall contract drilling profitability in the second quarter. As we move into the second half of the year, we anticipate that our rig count will increase driven primarily by activity in oil basins. In pressure pumping, the current market environment has resulted in some softness in the spot market for frac spreads. This softness contributed to increased white space in the calendar during the first quarter which, combined with weather disruptions, reduced utilization. But despite these challenges, I'm pleased that we were able to achieve our expectations for the first quarter revenues and margins due to the strong execution of our pressure pumping team. The pressure pumping industry continues to bifurcate as dual fuel spreads remain in higher demand due to their ability to reduce operators' fuel costs. Currently, 8 of our 12 spreads are dual-fuel capable. Given the current market environment, we no longer plan to reactivate our 13th spread this year. However, we will continue to convert engines to dual fuel and expect 9 of our 12 spreads to be dual fuel capable by the end of this year. In the directional drilling segment, our focus continues to be distinguishing ourselves by leveraging technology, innovation and emphasizing exceptional service quality and reliability. We have established ourselves as leaders in conventionally drilling U-turn wells, which involves utilizing a high-performance mud motor to drill complex wells shaped like a U, enabling clients to drill 10,000-foot laterals within a single 5,000-foot section. We've even successfully drilled a well in a W shape for a customer recently. Our impact mud motors and Mpower MWD systems have demonstrated outstanding reliability, contributing to the reduction in the number of trips required to replace tools and in turn, boosting operator efficiency. By combining this enhanced efficiency with top-notch service quality that ensures the wellbore remains within the pay zone, we can effectively improve overall well economics. As we move forward, we remain dedicated to maintaining our edge in the directional drilling industry by continually refining our technologies, fostering collaboration across our business segments and delivering reliable and efficient solutions that cater to the evolving needs of our clients. With that, I will now turn the call over to Andy Smith, who will review the financial results for the first quarter.

Thanks. Net income for the first quarter was $99.7 million or $0.46 per share. Adjusted EBITDA improved to $256 million for the first quarter from $239 million for the fourth quarter of 2022. In contract drilling, average adjusted rig margin per day in the U.S. increased by $2,430 over the previous quarter to $15,880. This growth was driven by higher average rig revenue per day which increased $2,930 due to the successful renewal of rig contracts to current rates. Average rig operating cost per day increased $490 to $18,880. At March 31, 2023, we had term contracts for drilling rigs in the U.S., providing for approximately $890 million of future dayrate drilling revenue, up from approximately $830 million at the end of the fourth quarter. Based on contracts currently in place in the U.S., we expect an average of 79 rigs operating under term contracts during the second quarter of 2023, and an average of 53 rigs operating under term contracts for the 4 quarters ending March 31, 2024. In Colombia, first quarter contract drilling revenues were $10.6 million with an adjusted gross margin of $2.1 million. For the second quarter, we anticipate further improvement in contract drilling profitability as the increase in margins resulting from contract renewals at current rates is expected to more than offset a slight decline in our rig count. Average adjusted rig margin per day is expected to increase approximately $1,000, while our average rig count is expected to decline 2 or 3 rigs. In Colombia, we expect to generate approximately $11.5 million of contract drilling revenue during the second quarter with adjusted gross margin of approximately $2.4 million. In pressure pumping, revenues and margins were impacted by both weather disruptions and increasing white space in the calendar. Pressure pumping revenues were $293 million, with an adjusted gross margin of $73.2 million. For the second quarter, we expect additional white space in the calendar given the softness in the spot market. Accordingly, pressure pumping revenues are expected to be approximately $277 million with an adjusted gross margin of $61 million. In our directional drilling segment, we experienced a decline in revenue and margin during the first quarter due primarily to reduced activity levels. Directional drilling revenues were $56.3 million in the first quarter with an adjusted gross margin of $8.2 million. For the second quarter, we expect both revenue and margin to increase by approximately $1 million over the first quarter levels. In our other operations, which includes our rental, technology and E&P businesses, revenues for the first quarter were $23.2 million with an adjusted gross margin of $9.1 million. For the second quarter, we expect revenues and adjusted gross margin to be similar to the first quarter. On a consolidated basis, in the first quarter, the total depreciation, depletion, amortization and impairment expense amounted to $128 million, including $4.4 million of impairment charges. For the second quarter, we expect total depreciation, depletion, amortization and impairment expense of $122 million. Selling, general and administrative expense for the second quarter is expected to be approximately $30 million. Interest expense for the first quarter of $8.8 million included a $1.1 million gain from the early extinguishment of debt related to the $9 million of debt we repurchased in the first quarter. For the second quarter, we expect interest expense to be approximately $10 million. Our effective tax rate for 2023 is expected to be approximately 17%, although we do not expect to pay any significant U.S. federal cash taxes. We are lowering our 2023 CapEx forecast to $510 million, which equates to $480 million when excluding $30 million of customer-funded rig upgrades. Contract drilling CapEx is expected to be approximately $290 million, down from our previous forecast of $320 million. The majority of this decrease is CapEx for maintenance and rig reactivations which is now expected to be $180 million, down from $200 million. Included in our forecast for rig reactivation CapEx is the reactivation of 6 rigs throughout 2023, and all are currently contracted. All 6 of these rig reactivations include very specific packages requested by the customers, including emission-reducing upgrades such as natural gas engines or utility skids for high line power. Additionally, approximately $30 million of this year's upgrade and reactivation CapEx was paid for by the customer. Patterson-UTI has a long history of being disciplined with our contracting strategy and we have no intention to reactivate any rigs without a term contract. Our pressure pumping CapEx forecast has been reduced by $20 million to approximately $150 million. As Andy mentioned, we no longer plan to reactivate a 13th spread but we are upgrading a spread to Tier 4 dual fuel. With that, I'll now turn the call back to Andy Hendricks.

Thanks, Andy. To summarize, we believe Patterson-UTI's positioned as a leading provider of Tier 1 super-spec rigs and our ability to leverage our technology in support of our customers' well economics through increased efficiency will result in a stable to slightly increasing rig count during 2023 despite any near-term pause in market activity. Given our term contract portfolio, we expect our operating results and cash flow will improve throughout the year as we will continue to benefit from the renewal of drilling rig contracts at higher rates. Furthermore, we will continue to demonstrate Patterson-UTI's long-standing commitment to capital discipline through both our capital spending and our contracting strategies where we prioritize cash flow and margin over activity levels. With our substantial free cash flow, we will continue to target a return of 50% of free cash flow to shareholders through a combination of dividends and share buybacks. With that, we would like to thank all of our employees for their hard work, efforts and successes to help provide the world with oil and gas for the products that make people's lives better. Cheryl, we'd now like to open up the call to questions.

Your first question is from Jim Rollyson of Raymond James.

It's impressive that the business is still performing well. One of the questions, Andy, is about what you mentioned regarding the ongoing transition of frac fleets to dual fuel or electric systems, particularly in relation to gas due to the significant fuel cost savings that are relevant today. You noted that you're upgrading another fleet this year, bringing the total to 9 out of 12 by year-end. Are you noticing a noticeable price difference between the older Tier 2 diesel fleets and the newer Tier 4 dual fuel models? Or is it primarily customer demand that influences those decisions? I'm curious about the short-term perspective.

Yes. So first, we continue to do the upgrade. It's been in our program now for over a year, but it really has to do with as we hour out some of the older Tier 2 engines to where it's no longer worth rebuilding then the new engines coming in are going to be Tier 4. And so that's the starting point. And then it is economically worthwhile for us to go ahead and add the dual fuel kits on top of that because we do get a bit of a premium because the benefit for the E&P is, of course, to be able to burn as much natural gas as they can when they can bring natural gas to the pads. So this is an ongoing process. It's part of our maintenance CapEx. I mean, it is an upgrade process, but the real upgrade is not just the Tier 4 engine, that's part of the maintenance and replacing older Tier 2s, but the upgrade portion is really just adding on the dual fuel kit, which is a smaller portion of the capital. So it's primarily part of the maintenance budget. And we think it continues to improve the quality of our fleet, the number of spreads that are on dual fuel are going to be increasing for us. And we get a bit better margin when we do that because there's a huge benefit to the E&P.

That's helpful. As a follow-up, you've shown a solid sequential increase in average revenue per day, and it seems that this trend will continue into the second quarter based on your guidance. One of your competitors noted ongoing strength in the oil basins, but they also mentioned some price declines in the gas basins. I'm interested to know if this has affected your fleet or financials and whether you've observed any changes in bidding behavior from others in recent weeks or months.

Yes. I mean I'm sure we're going to get a few questions on what day rates are doing and pricing. It's really about what we choose to do in the market. And our choice is that we don't see a need to reduce the rates on the rigs. We think that we've got high-quality rigs that can work. If we see any kind of slowdown in activity is just a pause, especially in the natural gas basins given the demand that's going to occur for LNG and feeding LNG trains and systems, and so we just don't see the need to reduce the rates. We still see demand in the oil basins. And so with any slowdown in the natural gas basins, we'll just wait and work those rigs when that activity starts to pick up again.

Your next question is from Saurabh Pant of Bank of America.

I'll start with the rig side and then possibly touch on pressure pumping. It's a bit unfair to ask you to comment on your competitors, but I can't resist bringing it up given the contrasting outlook for the second quarter. A few major peers have reported earlier, mentioning a 9% to 10% decline in their activity from the first to the second quarter. In contrast, your numbers suggest your activity is only expected to drop 2%. What do you attribute this significant difference to? Is it related to your basin or customer mix, how rigs roll off contract, or something else? The gap seems quite substantial compared to historical trends, so I would appreciate some clarification on this.

Yes, I think let's start that discussion by looking at what's going on in the different basins. I mean we are seeing changes happening in different basins in Bakken oil, we've seen some slowdown in Mid-Con. Mid-Con you're producing for both oil and gas and rigs drilling for gas have seen some slowdown in the Mid-Con. South Texas, you've got a mix of rigs drilling for some oil, some gas. And then, of course, you've got Haynesville covering East Texas and Louisiana. And so I think those are basins that, of course, we operate in but we're more heavily weighted, and this is a positive for us, to the Permian and also to the Northeast. Now the Northeast is a gas basin, but we anticipate that our activity stays relatively steady up here. That's a gas basin that's, as all of you well know, is a bit segregated from the rest of the pipeline structure in the U.S., and that services the Northeast industrial and heating market. And so we see stability in the Northeast. We see long-term growth in the Permian. And I think you're seeing some near-term challenges in Mid-Con, South Texas, along with the Haynesville, and while we operate there, we have less weighting in those basins. So I think it's just the basin waiting for different drilling contractors on how things are being affected right now.

Okay. No, that makes sense. And then just quickly on the pumping side, I think you talked about white spacing going up. Obviously, spot market looks like it's a little looser than it was 3 or 6 months back. In general, Andy, just help me think about how do you think about the decision point on whether you're willing to accept that extra white spacing taking, let's say, near-term hit to profitability, right? But like you said, this might be a pause and things might start to get better. How do you think about this taking a short-term hit on profitability due to white space versus just saying I'm going to stack 1 of my 12 fleets that are working on there.

Yes. It's a bit more complicated to fill out the calendar. We can't simply stack our resources and continue to assist our customers. We need to navigate some gaps, which will slightly reduce our margins. However, in the pressure pumping market where we operate, mainly in the Delaware Basin and the Northeast, we're observing that pricing remains steady despite the challenges from these gaps. Customers are currently reducing their schedules, and we'll need to adapt to that for the time being. I view this situation as more of a temporary pause. I believe that by later in the year, we will see increased activity that will help us fill the calendar and reduce these gaps.

Your next question is from Kurt Hallead of Benchmark.

Yes, there's a significant difference compared to some of your competitors, so great job, Andy, and congratulations to the entire team. I'm curious about the drilling dynamics, especially with your focus more on the Marcellus compared to the Haynesville and other regions. I understand the structural differences in that market, but I also recognize that your customers will always seek to negotiate better terms and pricing. Can you share some insights on your recent discussions? Have you noticed any changes in the usual challenges around pricing? Have the exploration and production companies become more aggressive than in previous quarters?

Kurt, the E&Ps certainly need to fulfill their role and initiate discussions. However, I wouldn’t say there has been a marked increase in aggressiveness, particularly in some of the more challenging gas markets like the Haynesville, which have been impacted by declining gas prices. Whether it's worthwhile to drill a well depends on several factors. Reducing the day rate on a rig by 10% or 15% isn't going to improve the economics enough to justify drilling a well. Therefore, I wouldn’t describe the current environment as experiencing significant pressure. The real challenges we are seeing are in specific basins such as Mid-Con, South Texas, and Haynesville, where gas production has slowed. We anticipate a decrease in the number of rigs in these areas, but at the same time, due to our reactivations, we are deploying rigs into the Permian and other oil basins. So, there are several factors affecting our rig count. Overall, we expect only a slight reduction in the number of rigs, reflecting our current positioning in various basins. In terms of being aggressive, I wouldn’t say that’s the case. It really comes down to our decision to avoid working at lower rates. While you may hear stories about some drilling contractors lowering rates, we hold our teams, rigs, and pressure pumping equipment in high regard and see no reason to follow suit.

Okay. That's good color. So a follow-up on the frac side. You obviously spell it out, you're going to have 9 exiting this year, 9 of the year 12 frac, which will be dual fuel. So I was just kind of curious as the market is evolving here and clearly moving towards the dual fuel for obvious cost reduction and efficiency gains and et cetera. What's your take on electric frac fleets and maybe longer term, Andy, how would you see the mix of your assets?

Yes. I'll let electric into various new technologies that employ natural gas as the primary fuel. And I think that there are some interesting technologies out there. It's not just electric. We're experimenting with a few, and we've seen some really good results. We've got some customers that are really happy with our ability to boost their ability to use natural gas at the well site and improve their economics. And we'll keep you posted on what we're doing later. But I don't see us buying, for instance, a new electric spread unless we were to get a term contract that really fully supported that investment and had a good return on that. I don't think that's going to happen in this environment, and we just haven't seen it. But I think we have some other things that we can do with some new technology to improve the use of natural gas.

Your next question is from Derek Podhaizer of Barclays.

I just wanted to go back to the comment around it seems like your rig gets a little bit more defensive than one of your larger peers. Obviously, they're dropping more than double than the rigs you are. I know you went through it a little bit, but can you also hit on is this also a function of your term versus spot contracts and then also your customer mix? Just maybe a little more color on those 2 dynamics to help us understand the differences between you and your peers?

Yes. Derek, it's tough for me to really say what our term versus spot is relative to our peers because I really don't know what they have. I would say we have good term coverage but I would take it back more to the basins and then some of the customers that we have in these basins, our weighting is more towards the Permian and the Northeast on the drilling rigs and even on the pressure pumping. And so we're seeing steady work up in the Northeast in that gas basin. And over time, I think we're going to see increasing activity in the Permian, especially depending on where oil goes. If oil goes back over $80 then yes, 100%, you're going to see the rig count and spread counts increase in the Permian and consume all available equipment on the market. So it's really more about the basins, I think.

Got it. You talked about the second half, you're expecting the rig count to increase here, so maybe bottom out over the summer months of that increase. Just can you unpack what it gives you the confidence to talk about a rig increase in the back half of the year? Are you talking to your customers? Do you have rigs locked up to come on to work? Just maybe a little bit of help around what gives you the confidence to see rigs going up in the back half?

It's really around discussions with customers. And even if what we're doing in the natural gas basin stays relatively flat, I think that throughout the year, you're going to see the potential to increase in the oil basins. And so that's going to drive a lot of that. Now, of course, where the commodity is going to drive the rate of increase, and we'll see how that plays out over the next few months. But on the natural gas side, in discussions with some of the customers, we do have customers that anticipate that they're going to need to get well inventory in the ground for the upcoming demand on LNG, and that's going to happen towards the end of this year and into 2024. So we do see this natural gas reduction in activity as a pause more than anything else.

Your next question is from John Daniel of Daniel Energy Partners.

I have three questions today. First, regarding the last topic you just addressed, Andy, if the rig count does increase later this year as we discussed, are you already in talks with those customers about rig pricing?

So for us, this is a pretty short discussion on the price of the rig. I mean the price is where it is. We think that where the rig rates have moved over the last years where they need to be and really pleased with how we continue to be able to reprice older contracts from last year at current rates this year, which is going to improve our margins quarter-on-quarter this year. So for us, with the type of rigs we operate and the performance track record of our teams and the technologies they're employing on the rigs, the day rate is the day rate.

Fair enough. To your credit, the larger players have been more vocal about defending prices. I'm curious, when we look six months from now at the overall rig count change, will we see a scenario where the larger public players may have lost a bit more market share because some exploration and production companies choose to use lower-priced rigs from smaller competitors? In other words, as the overall rig count declines, could it be less than what some of the guidance suggests from the top four companies?

It's hard for us to look at the overall rig count these days, given our coverage with customers, and we don't provide SCR mechanical rigs, we've seen those come down fast. We've seen those come down. We saw a lot of those rigs being used by private equity-backed E&Ps that were trying to prove up acreage. And they're trying to manage their P&Ls and their valuation. So I could see those rigs coming back and potentially taking share away from the larger drilling contractors, the public drilling contractors that are using super-spec rigs, but it is what it is. It doesn't affect us.

Okay. Last one's more of an operational question. Matador called out the U-shape lateral in their earnings. And you obviously referenced it too, I'm assuming maybe you're working for them. I'm curious, assuming you're doing the frac, how does that impact the utilization for the spread? What are the benefits to it? And how broad-based is this trend?

Yes. For the jobs that I know of that we're doing the hydraulic fracturing on the U-shaped wells, I'm not aware of any difference on how we operate those versus just a straight lateral. And we've done the U shape for a few different E&Ps. Certainly, the public data out there that shows that we work for Matador and really pleased to have them as a customer. and pleased to be able to trial some of these new technologies with them.

Your next question is from Don Crist of Johnson Rice.

Are you planning to stack rigs in the basin due to a potential pause or any weakness in your operations? Additionally, are you noticing competitors shifting rigs to higher activity basins? Do you believe a significant number of rigs could relocate to the Permian and impact spot prices there?

Yes. To start, we have stacked natural gas rigs in the natural gas basin. It’s already known that we had some rigs come down in the Haynesville, and we decided to stack them there. We believe this is just a temporary pause before the rig goes back to work. We can utilize crews in other areas to fill in the workload, so that’s not an issue. Will rigs move? Well, exploration and production companies are responsible for the moving costs. There may be instances where rigs move from one basin to another, but the costs are covered by the exploration and production companies. We have had at least one case where an exploration and production company paid to move a rig from South Central Texas to the Permian. So, while it does occur, I wouldn’t expect it to be a large number immediately. If some drilling contractors become aggressive in pricing, their situation is different. For larger drilling contractors, there’s no incentive to lower rates as that wouldn’t benefit them. We're all focused on doing the right thing for our shareholders. In contrast, if you’re a smaller drilling contractor and you’re losing a few rigs, that situation is significant, and you might do whatever it takes to keep those rigs working. We choose not to adjust our rates in that way.

Okay. And if I could sneak in 1 other one. Obviously, the rig count is coming in a little bit. Are you seeing any movement on steel or labor or any other kind of cost input given that there's more people available, et cetera?

Labor conditions remain tight. Operators are reporting issues with tubulars, particularly casing and drill pipe. We continue to procure high-end, high-torque, double-shoulder connection drill pipe from a reputable public supplier, and we have not encountered any issues with that; it remains a specialty item with significant lead time. On the completion side, we're able to acquire sand at better prices, which we are passing on to E&Ps where feasible. Overall, there are some cost savings for E&Ps, particularly related to casing and sand in certain areas, but I do not expect significant changes in service rates.

Your next question is from Keith MacKey of RBC Capital Markets.

I wanted to begin by discussing fracking. I appreciate the dynamics in the spot market. Can you explain your exposure to the spot market compared to the contracted portion of your fleet? Additionally, how do you anticipate this might change throughout the year?

We have about a quarter of our operations with some spot market exposure, and we're currently observing some opportunities in the calendar. I don’t anticipate any significant changes throughout the year. When I mention spot market, it may still refer to periods of time, not just a limited number of wells at once. There is some consistency even in that area, but we are noticing a bit more opportunity. However, this isn't really impacting service pricing directly; it's primarily influencing margins due to the timing of events on the calendar.

Got it. There won't be any additional spread activation this year, but regarding the dual fuel conversion, does that mean we won't see an additional activation for next year? Are the engines you currently have being utilized to replace existing equipment, and does that prevent you from establishing an additional fleet next year? Could you help us understand what CapEx and pressure pumping might look like next year in comparison to the $150 million this year?

So the upgrade to the Tier 4, again, is part of our maintenance budget. So that's coming out of the maintenance CapEx. And then the addition of the dual fuel systems, I consider that more an upgrade where we're going to try to get better rates for that. And I think the market still supports that. Again, no plans to reactivate, but that's really based on looking at current market conditions. Now if oil moves over $80 and it stays there for a fair period of time, that could change the dynamics going into 2024, and we could see some demand from existing customers today. So I think we just have to wait and see how this year plays out. And I think a lot of it will be driven by what the commodities do throughout this year.

Your next question is from Kurt Hallead of Benchmark.

A quick follow-up, coming back around to the other Andy's financial guidance. So if I do my math correctly, it looks like gross profit and operating income should be roughly flat with first quarter. Am I looking at it the right way?

On a consolidated basis?

Yes. Yes.

Hang on 1 second. I think that's about right, but let me pull something up here real quick. Yes. That's right.

There are no further questions at this time. I will now turn the call over to John Daniel of Daniel Energy Partners.

Real quick, when the market does recover, can you just speak to the timing and the cost of bringing the rigs back out? I mean I would assume not much, but just any thoughts.

When the market recovers, the timing and the cost...

To bring rigs back out.

Yes.

The timing is relatively short and the cost is relatively low. We don't see this as a reactivation that requires budgeting for growth capital expenditures because if a rig has been down for only a few months, not much work is needed. This differs from the economics of reactivating a rig that has been inactive for two years. In our capital expenditures budget, we have accounted for reactivations where it costs about $2 million to bring back a rig that has been down for a couple of years, and some of those rigs may require additional upgrades. Therefore, we consider that growth capital expenditure. However, bringing a rig back that has only been down for a few months will likely be classified as maintenance capital expenditure.

I will now turn the call over to Andrew Hendricks for closing remarks.

Well, I'd like to thank everybody who joined us on the call this morning and appreciate all the questions. And again, thanks to our team at Patterson-UTI for the great job that everybody is doing. Thanks.

This concludes today's conference call. Thank you for your participation. You may now disconnect.