Patterson-UTI Energy, Inc. (PTEN) Q1 2022 Earnings Report, Transcript and Summary

Please standby. We are about to begin. Good morning, ladies and gentlemen, and welcome to the Patterson-UTI Energy First Quarter 2022 Earnings Conference Call. At this time, all participants are in a listen-only mode and please be advised that this call is being recorded. After these speakers’ prepared remarks, there will be a question-and-answer session. [Operator Instructions] Now this time, I’ll turn things over to Mr. Mike Drickamer, Vice President, Investor Relations.

Thank you, Bove. Good morning. And on behalf of Patterson-UTI Energy, I’d like to welcome you to today’s conference call to discuss the results for the three months ended March 31, 2022. 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 www.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 first quarter conference call. Thank you for joining us today. I am very pleased with our first quarter results, especially within contract drilling where our better than expected revenue per day during the quarter illustrates how quickly day rates are increasing. Our average adjusted margin in the U.S. increased by $1,720 per day in the first quarter and we expect further margin growth in the second quarter of an additional $1,100 per day driven by a $1,600 increase in average rig revenue per day. For perspective, this is the strongest daily margin growth we have seen since 2013 and 2014. The base leading edge day rates for Tier 1 rigs is now in the upper 20,000 and including ancillary equipment easily over $30,000 per day at the leading edge, driven by increasing demand and a limited supply of readily available rigs. With the tight market some customers are already planning for their additional needs in 2023, which we expect to drive demand for longer-term contracts and also increase contract backlog. We are also seeing significant price increases for our services in both pressure pumping and directional drilling. And in our pressure pumping business, we are obtaining more favorable standby terms to help offset customer related downtime. With that, I will now turn the call over to Andy Smith who will review the financial results for the first quarter.

Thanks, Andy, and good morning. As Andy said, we are pleased with our first quarter results encouraged by our outlook. We expect pricing momentum for our services to continue and as such, we are increasing our expectation for total adjusted EBITDA for 2022 to exceed $500 million. In contract drilling, revenues and margins increased significantly over the fourth quarter due to the higher activity, increasing day rates and lower operating costs on a per day basis. In the U.S., our rig count for the first quarter increased by nine rigs sequentially to 115 rigs. In addition to the higher rig count, average adjusted margin per rig day increased by $1,720 per day to $7,170 per day, as average rig revenue per day increased by $1,100 and average rig operating cost per day decreased by $620. In Colombia, contract drilling revenues increased to $17 million for the first quarter compared to $15.8 million for the fourth quarter and adjusted gross margin improved to $5.6 million from $5.3 million in the fourth quarter. At March 31, 2022, we had term contracts for drilling rigs in the U.S. providing for approximately $400 million of future day rate drilling revenue, up from approximately $325 million at the end of the fourth quarter. Based on contracts currently in place in the U.S., we expect an average of 57 rigs operating under term contracts during the second quarter, and an average of 43 rigs operating under term contracts during the four quarters ending March 31, 2023. For the second quarter in the U.S., we expect our average rig count to grow to 122 rigs, while average rig margin per day is expected to increase by $1,100 per day, driven by a $1,600 increase in average rig revenue per day. In Colombia, we expect to generate approximately $18 million of revenue in the second quarter with approximately $4.5 million of adjusted gross margin. In pressure pumping, revenues and margins improved during the first quarter due to better pricing and the full quarter impact of the spread that is reactivated in the fourth quarter. Pressure pumping revenues increased during the first quarter to $190 million and adjusted gross margin improved to $32.1 million which included a $9.9 million benefit related to a sales and use tax refund. Additionally, we incurred approximately $2.5 million of expenses in the quarter due to increased receipts of spare parts and maintenance items as we work to stay ahead of any supply chain issues on critical items. Adjusted gross margin was impacted during the quarter by customer-related downtime. With the current market tightness, we have recently been able to increase the standby rates we receive for customer-related downtime. The reactivation of our 12th spread has been delayed due to the tight supply chain conditions for hardware components. We now expect to reactivate our 12th spread late in the second quarter. For the second quarter, we expect our pressure pumping activity to increase as the weather improves. Taking into account, the delayed spread reactivation we expect pressure pumping revenue to increase during the second quarter to $205 million and adjusted gross margin to improve at $33 million. In directional drilling, first quarter revenues and margins increased due to higher activity and more favorable pricing. Directional drilling revenues increased 23% in the first quarter to $43.3 million and adjusted gross margin improved to $6.4 million. For the second quarter, we expect revenues to increase to approximately $50 million with an adjusted gross margin of approximately $8 million. In our other operations, which includes our rental technology and E&P businesses. Revenues for the first quarter improved to $19.8 million and adjusted gross margin improved to $7.7 million. For the second quarter, we expect that the revenues and adjusted gross margin in our other operations to be similar to first quarter levels. On a consolidated basis, we expect total depreciation, depletion, amortization and impairment expense to be approximately $116 million for the second quarter. Selling, general and administrative expense during the first quarter included $3.1 million of higher than expected compensation expense directly related to the increase in our share price late in the quarter. For the second quarter, SG&A is expected to be approximately $25 million. We did not expect a meaningful amount of tax expense or cash taxes for 2022. For CapEx, we are maintaining our 2022 forecast of approximately $350 million. We expect our CapEx spend to be more heavily weighted to the first half of the year as we try to say ahead of increasing lead times for various parts and components. Turning now to our cash flow. Increasing working capital was a drag on cash flow during the first quarter, as we worked off some prepaid revenue during the quarter and made payments of some large accrued expenses. We believe this was largely a function of timing and we expect working capital to moderate and our cash balance to increase over the remainder of the year. With that, I’ll now turn the call back to Andy Hendricks.

Thanks, Andy. I’ll start by saying that we fully recognize what is happening in Ukraine is a human tragedy. And I can’t imagine the suffering of the people in that region. And while this tragic event drove world oil prices higher, it was not the catalyst for increasing activity levels. The increase in demand for oil and gas was driven by the reopening of world economies. It is this fundamental increase in oil and gas demand over the last six months, it has driven a rapid increase in the demand for equipment and services in the U.S. drilling and completions markets. This has led to a strong pricing environment where drilling and completion pricing has climbed rapidly. I don’t recall another period where leading edge day rates for drilling rigs moved up this quickly. The supply of high quality equipment is now very limited and any meaningful increase in drilling or completion equipment capacity across the market is further limited by global supply chain challenges, where there are longer lead times for various raw materials and manufactured components such as structural steels, steel tubulars, engines, and electrical components. With regards to labor as we have discussed before, last year, we ramped up our systems for recruiting, onboarding and training in order to find the people that we need. And while we haven’t missed any work, it is the challenge in the current market to hire and retain people. E&P operators are used to picking up the phone and being able to get what they want from drilling contractors and service companies, but the industry no longer has this excess capacity. Some operators may not recall similar market conditions the industry has had in the past such as the period from 2012 to 2014. We have recently seen situations where for various reasons a few operators have been slow to commit and then the assets were no longer available or the pricing in the market had taken another step up. And now, as I’ve said, we are in a very tight market. At this point, if you are an operator looking to increase your activity and you don’t have an agreement for a Tier 1 super spec rig or for a frac spread, you may have a challenge to find what you want. We will always try to work with our customer customers to get them the equipment and services they need, but the industry is now constrained in its ability to respond as quickly as the industry had in the past. Our expectation is that going forward operators will have to commit to higher prices to keep the equipment and crews they have today. So they don’t lose them to other operators. Based on the current global energy situation, we expect the market for our equipment and services to continue to remain tight and for pricing to continue to increase. Market conditions for contract drilling and other oil field services are likely to be the best that has been seen in a decade. It continues to be an exciting time for Patterson-UTI, and we look forward to the continuing financial growth. With that, we would like to thank all of our employees for their hard work, efforts and successes to drill and complete wells better each day. Bove, we’d like to now turn the call over for questions.

Thank you, Mr. Hendricks. [Operator Instructions] We go first this morning to Connor Lynagh at Morgan Stanley.

Thank you. Obviously, the anecdotes that we’re hearing on the leading edge pricing on both drilling and pressure pumping are very strong. I guess just to level set, in terms of your ability to price to that leading edge, is it as simple as just looking at your contract book roll off, do you think that we should expect that sort of high twenties to even up to $30,000 a day to be something that we see in your numbers in later this year, early next year? Or how would you recommend if you think about that?

I think there’s still a lot of upside to what we have in our average rig revenue and margin per day. As we work through that, we have a number of agreements that are currently in place that have been in place for a while, but as things reprice they’re just going to continue to move upward.

So just to be clear, do you think that sort of high 20s is indicative of what most of your rigs can price at or is that sort of the best rig in the market and we should risk it lower? I appreciate that. I’m probably trying to put too fine a point on it, but just trying to get some directional guidance here.

Yes. I think, this is leading edge day rates for Tier 1 super spec rigs. Today, we’re working 109 of those in our fleet and that’ll increase as we do upgrades this year. And so, I still see that there’s a lot of room to move pricing up and it’ll extend into 2023. It’s hard to put the timing on when it’s all going to move to leading edge in the upper 20s for the base rate or over 30,000 with everything in, but it’s continuing to move up in the next year.

Okay. Got it. And then on the supply chain and labor side of things, do you see, obviously, price is going to have to move higher for a lot of things labor potentially included. Do you see a potential needs to, for the, either yourselves or the industry in general to raise wages in order to attract labor, or do you view it’s more of a structural issue that can’t be addressed with price?

We gave some large wage increases last year, and those have been baked into our numbers since Q4 results. And at this time, and we’re still recruiting and we’re still hiring. But at this time, we don’t have visibility on a strong need to raise wages from where we are, maybe some small increases going forward, but not to the extent that we did last year, at least on our current visibility.

All right. Thanks very much. I’ll turn it back.

Thank you. We go next now to Don Crist at Johnson Rice.

Good morning, gentlemen. How are you all this morning?

Good. Good morning.

I think, a lot of us have scratched our heads over the last quarter as the rig count is moved as fast as it has. Obviously, the rig count is or the rig market is very tight today. But I know in the past all thrown out where you all think the rig count may be at year end. Are you all still sticking to that kind of 700-ish range, 725 or so range at year end? And do you think that it gets kind of frictional from here in the rig market?

So I think it somewhat depends on how you’re looking at the numbers in the rig market. I was saying for the last couple quarters that that the overall industry rig market by the end of the year would go to 650 to 700. I think I was wrong on that. I think it’s going to be higher. I think it’s going to be above 700 rigs in the total count at the end of the year. I think we’re going to see continued activation of rigs as we work through this year. So the market is just that strong right now.

Okay. And obviously super spec rigs are an impediment, but are there any other impediments out there from a casing or a drill pipe or any other perspective that could impede a significant amount of rigs coming back to the market saying other 50 rigs coming into the market today?

Yes. So when I talk about rig count going up over 700, that includes operators that have programs in place that have their casing on order et cetera. So that number, I don’t think is impeded. I think, there are constraints on whether – for operators buying casing for us buying drill pipe and other components. But it’s just about planning around longer lead times. So the visibility we have on the increasing rig count tells us in the discussions that we’re in with operators that they’ve already lined up the things they need on their side, and we’ll be working to line up the things we need on our side.

Okay. And just one more if I could sneak it in at the end here. What is your average contract duration now and are the majority of your contracts going to roll to higher prices this year?

So, yes, the majority of our contracts all work backwards are going to roll to higher prices, no question. The duration has been shorter. We’ve signed – contracts we’ve signed over the last year have been short in that six month range. But we’re going to start to extend that the market is just that tight day rates are that high that we’ll be signing more certain contracts and increasing backlog as we work through the year.

Okay. I’ll turn it back. Thanks for the answers.

Sure. Thanks.

Thank you. We go next now to Ian Macpherson at Piper Sandler.

Thanks. Good morning, Andy and Andrew.

Good morning.

So you’ve got the unique perspective of the hybrid driller and pumper, and we know that everything is tight. Do you see the ratio of rigs and spreads as being in balance in the second half year? I think there’s been – we’ve obviously seen an ability and a demonstrated trend of rigs recovering more than maybe frac activity has year-to-date. Maybe frac will be a little more capacity constrained in the back half of this year, but how do you see that ratio unfolding over beyond this year into 2023?

Yes. So if you look at the data back into 2021, and you look at our data specifically on spread count and rig count, you saw our spread count start to move up about six months before our rig count really started to move up. And so we had a number of operators that were reactivating spreads in 2021 to go through and frac ups. It still existed after the downturn of 2020. And then we saw the rig count start to ramp up about six months after that following the spread count ramp up. So while you’re seeing that in this year’s numbers, I think things are normalizing back to a level where we have a normal number of rigs in front of the spreads. And so even though yes, drilling efficiency is improved, but also frac efficiency is improved. So I think we’ll get back to the normal number of rigs in front of the spreads that we’ve had in the past pre-2020, because we’ve had improvements, efficiencies in both. But I think we get back to those same levels. I think the duck out has essentially worked through and we’re having to drill new wells.

Yes. So the other question I had for you Andy is, what do you think happens from we get – we’re getting closer to running out of super spec rigs, and then we’re going to have to have a combination of much more expensive reactivations with more substantial upgrades on SCR rigs or whatever, Tier 3 rigs can be upgraded or we’ll have to go to new builds, or we’ll have to go to customers accepting lower spec rigs at lower price points. I guess those are probably three options for when the rig count gets too high. Where do you think that the demand is likely to go first if we get to that point?

First, I’m going to scratch one of your options. So new build rigs is not on the table. There’s a sufficient number of rigs that are good quality rigs that can be upgraded to super spec and Tier 1 super spec. So that can still happen. So we’re not even thinking or considering new builds. And when you look at our budget and our plan this year, we’ve got about 10 upgrades that we’re doing in the budget. We’ve got another two dozen rigs that can be upgraded at relatively low CapEx to get them to what we call Tier 1 super spec. So we still have the ability to do that. It does take time. There’s lead times to do that. But as well, you pointed out that, there are existing rigs that can go back to work. And I think you’ll see some of those go back to work as well, because if you need a rig in the next two months, you need to take something that exists today without a significant upgrade. But if you want the upgrades, you’re just going to have to wait till we can get the components and get that done.

Okay, great. Thank you.

Thanks.

Thank you. We go next now to Taylor Zurcher at Tudor, Pickering and Holt.

Hey, and thanks for taking my question. My first one, you talked a little bit about contract durations, likely extending moving forward. And I guess I’m just curious about the pulse of EMP operators today with respect to the pricing momentum that’s happened pretty suddenly here. When you talk about extending durations, I mean, is there an appetite from the customer perspective to lock in terms for multi years in the high 20s, low 30s, or are we talking kind of 12-month term contracts on the come when you talk about longer durations?

I think there is appetite, especially among operators that have large programs to lock in contracts for longer periods, just so they can protect themselves. But I think, when we talk about the pulse of the operator, as you stated, it’s still evolving, they’re still getting used to this market. This market has been moving really fast. And as I tried to explain, we’ve had a number of conversations with operators that while they go back and think about what they want to do and they call us back, it’s like, sorry, that asset is gone or the market’s moved up again. And so those have been some tough discussions with operators, but that’s what’s happening in the market today.

Got it. And then a follow-up on contract drilling. So if I was doing the math correctly on the guidance, I mean, you’re basically at mid $16,000 a day type OpEx per day for Q2 and a quarter where you don’t much reactivation cost at least non optically. So I’m just curious with all these inflationary dynamics at play, if the new normalized type OpEx at the rig level is somewhere in the mid $16,000 day range moving forward.

I think it’s going to depend on the quarter and depend on the number of rigs that we’re working with fixed cost coverage, et cetera, or activations, but we think it’s around 16,000 to 16,500 a day.

Got it. And one last one for me pressure pumping, the mark is likely to be a pretty tight here for the balance of 2022. I imagine at some point pricing, if it’s not already there today, it’ll get there to sent you to at least consider reactivating more spread. So curious for the latest and greatest there when it comes to reactivating spread 13, 14 and beyond for Patterson?

Yes. We’re not even discussing reactivations at this point. We’re very focused and the team’s doing a great job at working with our customers to get things closer to the leading edge in terms of pricing. And that’s our focus today.

Understood. Thanks for the answers.

Thanks.

Thank you. [Operator Instructions] We go next now to John Daniel at Daniel Energy Partners.

Thanks for including me. Two quick ones for you, just Andy, what’s the lead time today on drill pipes?

So lead time on drill pipe is running around a year, I would say for double shoulder high torque connections. And so we were ordering drill pipe in November for delivery this November. So it’s just a matter of staying ahead. And we started adjusting our orders and lead times last year for that.

Okay. Thank you. And then the second one is, as you’re talking to customers who try to look forward to 2023, just given how tight everything is today, do you have the reason to suspect that we see a step change increase in reactivity in 2023, or is it just a slow grind higher?

2021 and 2022 have really been led by the privates in terms of rig count increases, especially privates with large programs. And I think what you’re going to see is we worked into 2023 is some of the larger publics kick in with some of their programs and increase rig counts there. And so, it’s kind of hard to predict exactly what that’s going to look like on a chart in terms of pace and all, but I think you are going to see somewhat of a step up in 2023 just based on discussions that we’re having.

Okay. Thank you very much.

Thank you. And Mr. Hendricks, it appears we have no further questions this morning. So I’ll turn the conference back to you for any closing comments.

Thanks, Bove. That’s fine. We know it’s a busy day for a number of calls and we appreciate everybody that dialed in and appreciate the questions today. And again, thanks to all of our team at Patterson-UTI for a great quarter. Thanks.

Thank you. And ladies and gentlemen, that will conclude today’s Patterson-UTI Energy first quarter 2022 earnings conference call. We’d like to thank you all so much for joining us and wish you all a great day. Good bye.