Patterson-UTI Energy Inc (PTEN) 2022 Q2 法說會逐字稿

Good morning. My name is David, and I'll be your conference operator today. At this time, I'd like to welcome everyone to the Patterson-UTI Energy Second Quarter 2022 Earnings Conference Call. Today's conference is being recorded. (Operator Instructions) Mike Drickamer, Vice President of Investor Relations, you may begin your conference.

Thank you, David. 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 3 months ended June 30, 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, 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 second quarter conference call. Thank you for joining us today. I am pleased with our outstanding second quarter results as we achieved significant increases in activity and pricing. Market fundamentals are strong and demand is increasing for drilling and completions equipment and services.

On top of that, the industry supply remains constrained. We expect the strong market for our services to continue, and we anticipate further improvements in pricing and activity. Therefore, we are increasing our forecast for 2022 consolidated adjusted EBITDA, which we now expect will exceed $600 million. We are also slightly increasing our 2022 CapEx forecast to $390 million due to increasing activity, including long lead items for rigs that will return to work in 2023, along with cost inflation.

Turning now to my review of operations. First, I'm very proud of the solid execution at each of our businesses and their success in increasing both activity and pricing this quarter while continuing to provide the high level of service quality that our customers have come to expect from Patterson-UTI. In contract drilling, our average U.S. rig count for the second quarter increased by 6 rigs to 121 rigs. As of today, we have 127 active drilling rigs in the U.S. along with 5 additional rigs that are committed to return to work in 2022. We are also finalizing contracts for some rigs to be upgraded and activated in 2023.

Pricing for contract drilling is strong as leading-edge day rates for Tier 1 super-spec rigs are in the low to mid $30,000 per day. And then in the mid to upper $30,000 per day when you consider all of the technology and ancillary equipment. Across the industry, we estimate Tier 1 super-spec rig utilization is greater than 90%. Within our own fleet, utilization of our 116 Tier 1 super-spec rigs is greater than 95%, and all of our Tier 1 super-spec rigs in the southern U.S. are currently active.

Industry rig demand continues to increase with the active rig count at the highest level since early 2020. Also, supply is limited with the lower-cost reactivation to super-spec rigs having already taken place. The availability of fully crewed super-spec rigs is almost nonexistent as few customers are willing to give up rigs. I am aware that there are some operators that are holding off on the signing of a contract to reactivate a super-spec drilling rig because they are waiting for an active super-spec rig to free up, in other words, a hot rig. However, we don't have any visibility on any of our rigs coming available and anticipate that our rig count continues to be higher.

Most of the industry's idle rig capacity will likely require meaningful reactivation and upgrade CapEx to go to work, which will have to be supported by term contracts. At Patterson-UTI, we are well positioned to economically upgrade additional rigs. Many of our idle rigs are of the more modern design with the drawworks set at the level of the rig floor, which will be cheaper to upgrade to the Tier 1 status than rigs that have the drawworks on the ground.

In order to spend the necessary capital to upgrade and reactivate additional rigs, we expect term contracts, and we will be disciplined in negotiating for these terms. And in certain cases, we will be receiving upfront cash payments to derisk our capital investment and reduce the impact that reactivation and upgrade CapEx will have on our cash flow.

In pressure pumping, we achieved higher activity and better pricing during the second quarter. We reactivated our 12th spread in June, a Tier 4 dual fuel spread and 7 of our 12 spreads are now utilizing dual fuel. We continue to focus on maximizing the profitability of our 12 spreads with no additional spread reactivations planned this time.

In directional drilling, we remain focused on technology, any new developments to enhance wellbore placement performance and improved wellbore quality. We continue to grow our rotary steerable system service, where we have acquired additional rotary steerable tools and hired and trained more personnel with experience on these systems.

Additionally, we've been successful in reducing the number of people on the rig and improving margins by utilizing remote operations to transition one of the well site technicians to a remote position here in Houston at our MS Directional GOTEC Center.

We recently commercialized our directional drilling advisory program, HiFi Guidance. This cloud-based program increases the reliability and consistency of directional drilling services to improve wellbore quality, increase rate of penetration and also reduce drilling days. HiFi Guidance is also designed to communicate with our drilling rigs, Cortex automation control systems for improved directional performance.

Looking ahead, we continue to believe that the industry is in a multiyear upcycle. We expect the U.S. onshore industry rig count to increase through 2023. Therefore, we are currently in discussions with a number of operators to add rigs in 2023, where reactivation and upgrade CapEx on those particular rigs could be $4 million or more and with the expectation of a term contract to achieve sufficient cash returns.

With that, I will now turn the call over to Andy Smith, who will review the financial results for the second quarter.

Thanks, and good morning. As Andy said, we are pleased with our second quarter results where we achieved improved revenues and margins across all of our segments. Net income for the second quarter was $21.9 million or $0.10 per share compared to a net loss of $28.8 million or $0.13 per share in the first quarter. Financial results for the second quarter include a noncash gain of $11.5 million related to the release of a cumulative foreign currency translation adjustment associated with the substantial completion of our exit from Canadian operations.

In contract drilling, revenues and margins increased significantly in the second quarter due to continued day rate pricing momentum, contract renewals and rig reactivations. In the U.S., our average adjusted rig margin per day increased by $2,220 as average rig revenue per day increased by $2,770. Average rig operating cost per day increased $550 to $16,500 as expected.

At June 30, we had term contracts for drilling rigs in the U.S., providing for approximately $440 million of future day rate drilling revenue, up from approximately $400 million at the end of the first quarter. Based on contracts currently in place in the U.S., we expect an average of 71 rigs operating under term contracts during the third quarter at an average of 46 rigs operating under term contracts over the fourth quarters ending June 30, 2023.

At the beginning of the third quarter, we implemented a wage increase for our U.S. drilling rig-based personnel. We passed this wage increase through to our customers such that we expect the impact of both our average revenue per day and rig cost per day to be approximately $600 with limited impact to our average adjusted rig margin per day. For the third quarter, we expect our average rig count in the U.S. to increase by 7 rigs to 128 rigs. Including the impact from the wage increase, we expect our average revenue per day to increase approximately $2,100 per day to $28,000, and we expect our average adjusted rig margin per day to increase by approximately $1,000 to $10,400.

In Colombia, one of our rigs is anticipated to have standby time during the third quarter, which is expected to reduce both revenues and costs, while having a minimal impact on margins. For the third quarter, we expect to generate approximately $15.5 million of revenue in Colombia, with adjusted gross margin of approximately $4.8 million.

In pressure pumping, revenues and margins improved during the second quarter due to better pricing, higher utilization and more favorable contract terms. Pressure pumping revenues were $238 million for the second quarter, an increase of $48.8 million, or 26% from the first quarter. Adjusted gross margin was $46.9 million, an increase of $14.8 million or 46% from the first quarter. For the third quarter, we expect pressure pumping revenue to increase to $250 million and adjusted gross margin to improve to $52 million.

In directional drilling, during the second quarter, we were able to achieve better pricing with higher activity levels, resulting in increased revenues and margins. Directional drilling revenues increased 27% in the second quarter to $54.8 million and adjusted gross margin improved to $9.4 million. For the third quarter, we expect incremental pricing gains with activity levels consistent with the second quarter. As such, we see third quarter revenue essentially flat at $55 million, while adjusted gross margin is expected to grow to approximately $10 million.

In our other operations, which includes our rental, technology and E&P businesses, revenues for the second quarter improved to $24.5 million and adjusted gross margin improved to $10.7 million. For the third quarter, we expect both revenues and adjusted gross margin in our other operations to be similar to second quarter levels. On a consolidated basis, we expect total depreciation, depletion, amortization and impairment expense to be approximately $121 million for the third quarter. Selling, general and administrative expense for the third quarter is expected to be approximately $26.5 million. We do not expect a meaningful amount of tax expense or cash taxes for 2022.

Turning now to our cash flow. Higher revenues resulting from a significant increase in activity and pricing in the first half of the year has resulted in a larger than anticipated working capital build. Additionally, the combination of a large prepaid revenue amount late last year and shorter payment terms on critical items have resulted in lower cash flow in the front half of this year. We anticipate these issues will abate in the back half of the year -- and given our current levels of profitability, we continue to expect positive cash flow for 2022.

With that, I'll now turn the call back over to Andy Hendricks.

Thanks, Andy. We believe the commitment to financial discipline seen throughout the energy sector has changed the playbook, and we continue to believe that we are in a multiyear upcycle. The U.S. is not likely to be the swing producer in the global crude oil market as public E&P companies have shown strong financial discipline to prioritize returns over growth, which should help to reduce the magnitude of the cyclical swings relative to what has been seen over the past decade. Similarly, U.S. oilfield service companies have shown incredible discipline in reactivating and upgrading equipment, which has supported unprecedented growth in pricing for drilling and completion equipment and services, and allowed oil field services companies to share in more of the financial benefits that are being realized by E&P companies from increased efficiencies and higher commodity prices.

Patterson-UTI is well positioned to benefit from the current strength in market fundamentals. As the only company in the U.S. that offers contract drilling, pressure pumping and directional drilling services, we are uniquely positioned to benefit the concurrent strength across the U.S. oil service market. As a leading provider of Tier 1 super-spec rigs, we will continue to push day rates and contract terms while maintaining a disciplined approach to activity growth.

As well in pressure pumping, we will continue to push pricing, especially as demand remains high for dual fuel spreads, which are capable of reducing fuel consumption and emissions. In directional drilling, we will continue to leverage our technology position to more efficiently drill better wells, allowing us to grow our revenues and margins.

In summary, I'm very pleased with our second quarter results and the strong market fundamentals. At Patterson-UTI, we are well positioned to benefit from what we believe will be a multiyear upcycle. With that, we'd like to thank all of our employees in the U.S. and Colombia 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.

David, we would now like to open the call to questions.

(Operator Instructions) And we'll take our first question from Chase Mulvehill with Bank of America.

So I guess the first question, if you look at the rig count, you guided, I think, 128, and if the math has that correct where your rig count is today versus kind of where you would exit, I think that's kind of 3 or so rigs that would be added over the last couple of months. So a little bit of slowing momentum on rig adds, which I don't think is going to surprise anybody. But my broader question is, as we look into 4Q, would we expect kind of still slowing momentum? Or do you think that rig activity will actually pick up in the fourth quarter?

So we have 5 additional rigs that are committed to go to work in 2022. We're still going to see activity increases not quite at the pace that we've seen for the last 1.5 years, but it's still going to increase going through the rest of the year. There are some constraints on rig supply, but that's positive for pricing in the market. Then I think as we get into 2023, we're going to see a step-up in activity. So we see continuing increasing activity in the rig market.

Okay. And kind of, I guess, a follow-up there. If we kind of exit around 135, I guess is kind of what you're saying here is thereabouts and just kind of look at your contract coverage into the first half of 2023, we try to do some math there. I think it's about 20% of that 135 rigs contracted in the first half of next year. So I guess my question would be with leading-edge day rates where they are, low to mid-20 -- sorry, low to mid-30s and still strong demand from the E&Ps out there to lock up these rigs, I would have thought there may be a little bit more contract coverage out there. So I guess maybe just talk about your strategy. I guess -- does it mean that you think that day rates still have significant more upside? Or is there a little bit more reluctance on the E&Ps to go ahead and lock in more rigs for 2023?

Definitely, the leading edge on day rates has been moving up quickly faster than we've ever seen in the industry. And we're working 127 rigs now, adding 5 more for the rest of the year, but we still think there's opportunity to push the day rates on a large number of the rigs that are still working. And so we haven't gone in to sign a lot of term contracts yet. If you look at our average length of the term right now, it's in the range of 6 months to a year, but we expect that to extend. So you'll see that extend as we get into rig signings for 2023 deliveries.

Okay. And when we think about day rates into 2023 and if you're starting to kind of sign some of those today, would you think that you would get them kind of at or above kind of the leading edge of that low to mid-30s or kind of just more in line? Or you get out to 2023, are you seeing the curve backwardated at all?

So when you see the rate at which the leading-edge day rate has gone up. And I want to make sure I explain this, so everybody understands. This thing is moving fast. And it's going to continue to move up. Activity is still going up and there is constraints in the availability of Tier 1 super-spec rigs. And so for us to deliver more Tier 1 super-spec rigs, we're going to be in further negotiations with increasing day rates at that leading edge.

Next, we'll go to Derek Podhaizer with Barclays.

I just want to hit more about on the day rate required for next year in term. Could you maybe break it down into the different buckets as far as what upgrades are required, be it in the low single-digit millions, mid- to high single-digit millions and then moving up to the low double-digit millions? Just wanted to get some more color on what day rate you would need and what type of term you would need in order to hit the paybacks that you're looking for and to get those rigs out into the field for next year? Really just how do we move from low to mid-30 day rates to high 30s? Just some more color on that would be helpful.

Yes. So when we say low to mid-30s, that's just the rig by itself, doesn't include all the ancillary equipment and technology that we layer on. When you add all that in, you're in the upper 30s and approaching 40. And so we're really encouraged by how this market is shaping up. And these day rates aren't necessarily always tied to what an upgrade may cost. We're just talking about what the market is and what E&Ps are willing to pay in a tight market for drilling rigs.

When we do look at the upgrades going into 2023, we've got a number of them that we're going to do in that $4 million range. And that's what it costs us to do some of these upgrades. We're well positioned with some of the rigs that we have in the fleet to do some upgrades that we think are really economical to get them to Tier 1 super-spec. But aside from that, it's not directly related to what the day rate is. The day rate is based on how tight and constrained this market is right now and the demand for rigs.

Got it. Okay. That's helpful. Switching over to pressure pumping, obviously, a historic quarter for you guys. You're at about a $15 million EBITDA per fleet guiding to around $16-ish million -- $16.5 million clearly, $20 million is in the line of sight. I know the message is you're staying at 12 spreads today. But the question is, could you add more if you wanted to, given these pricing signals and what Tier 2 diesel is going for in setting the market? Could you add 13, 14? Or would any incremental capacity have to be new pumps, new builds?

A couple of things on that. So we're really pleased with the success of the team at Universal Pressure Pumping and how they've been able to react to the market and push the pricing up and improve the margins and the EBITDA per spread. They're doing a great job there. They're also doing a great job from a service quality standpoint out in the field that allows us to move pricing. And I expect there's still some more pricing movement that can happen there.

With the type of work we do, it's pretty intense. We do a lot of high-pressure work. So the number of pumps per spread has gone up, I would say, across our fleet, and that's not uncommon across the industry today, especially when you look at the Utica and the Delaware. And occasionally, we're doing some simul-fracs, too, where you have a large number of pumps on location.

So to get to #13 may require us to purchase some additional pumps. It's not out of the question in the future, but today, we're still going to stick at 12. We think that's the right answer for investors. Our focus is trying to return cash to shareholders. And our team at Universal today is focused on pushing pricing and taking advantage of the market conditions that we have in improving the margins in that business. And so there's not a reason for us to activate another spread today. We don't think we get judged on our market share. We get judged on the earnings we produce, and we want to have earnings that we can return to shareholders. So we'll evaluate all this, but today, we're just going to stick at 12 spreads.

Got it. That makes sense. And just to sneak one more in about pushing price. What kind of openers do you have on the overall fleet? How quickly can you move that EBITDA per fleet up the curve? If you could just talk about the openers there would be helpful.

Yes, with 12 working and a number of agreements in place, it's not right away, but I think the market is essentially sold out for frac. And it's created this condition that it's allowed us to move price. We'll just have to wait and see how some of these agreements reprice as we work over the next 6 months or so.

Next, we'll go to Don Crist with Johnson Rice.

Andy, I wanted to ask about the CapEx for rigs going into next year. I'm guessing that those are long lead time items like pumps and generators that you need to buy to upgrade the rigs. And just wanted to get any more color around that and kind of the supply chain for that equipment. Is it a 6-month wait for most of that equipment? Or is it longer than that?

Yes, this is Andy Smith. Yes, we're seeing lead times on that stuff, 6 months right now is probably a base level and then you get a little bit longer than that on a few items. So that's one of the reasons that we've kind of upped CapEx a little bit is that we've got to get in front of some of it this year, some payments out to get that stuff in and have them ready for next year.

Okay. And I wanted to ask about the contract coverage between privates and publics. I think we're all in agreement that the publics will probably add a significant amount of rigs in the first quarter of next year as they flow through their CapEx plans? And where do those rigs come from? Do they displace the privates that are kind of working today? Or is it all going to be incremental new rigs that kind of come off the fence?

This is a great thing about large private E&Ps. They get to do whatever they want. And right now, they're not giving up drilling rigs. They want to drill. They're producing great cash flow, and that's what private companies do. And some of these private companies are large and you've got a public company that's about to be private. So I suspect that they're just going to keep drilling. The adds that the large publics will eventually make are going to be incremental. Nobody has given up drilling rigs right now.

Next, we'll go to Sean Mitchell of Daniel Energy Partners.

I'm just wondering, can you provide any additional color. You've talked a little bit about the rig upgrades in that $4 million category. Have you tried to frame numbers around how many of those opportunities are available in '23 would be the first question.

And then the second one is we've heard over -- at least last quarter, there was lots of questions on these calls about labor issues, and I haven't really heard much talk about labor issues this quarter. What are you guys seeing on the labor side as you kind of bring things back to work and things heat up? Is it still really, really hard to find folks or any commentary around labor would be helpful.

Sure. So I'll start with the drilling rigs and the CapEx. So we have about 19 in total, which means about 14 left in 2023 that fall into that $4 million range. And there's a number of things that will happen to those rigs. They may get an upgrade on a pump or a gen set, they may get an upgrade on rack-back capacity structurally. And then some of that CapEx is just funds the reactivation for those rigs as well. And so it's a mix that's in there, but we have a large number that we think are economical. And so we think we're in a really good position to be efficient with capital and be competitive on the market to be able to activate rigs.

The people question is still out there. Maybe you haven't heard as much and we didn't particularly mention it today. I will give hats off to our HR teams across Patterson-UTI, across all of our businesses. They're doing a great job finding people. We're not missing work because we don't have people, but it's a lot of work to go find the people. We have to hire a large number for the few that decided to stay. This work is not for everybody. People have choices in the economy today. And so it is a lot of work to go out and recruit and find the people and we have broad systems to be able to do that. We have in-person recruiting. We have online systems that we're using and our HR team is testing some new artificial intelligence-driven systems online where people can log in and do this over the weekend and try to get an interview with us, and we can do that pretty fast.

We're trying our best to increase the turnaround time from the time we first meet somebody to the time we get them their first paycheck. And once we get somebody working for us, if we can keep them for a while, we generally keep them for a long time. And so that's our objective. And we're also looking at lifestyle out in the field and things like that. It's still a challenge. Like I said, we haven't missed worked, but it's a huge effort from our HR teams across our company, and it's a good time for me to thank them this morning.

(Operator Instructions) Next, we'll go to Keith MacKey with RBC Capital Markets.

Just first wanted to start off on cash flow. Andy, I think you talked about positive free cash flow for 2022. It looks like the toggle on that will be working capital. So maybe if you could just give a bit more color on what you expect for working capital and free cash flow over the back half of the year, please?

Yes. So the first half of the year obviously was a struggle a bit with sharply increasing revenue, sharply increasing profitability, but also revenue, obviously, the collection of that profitability takes a little bit of time to work itself through the system. So we've added some working capital in the first half. The first half is also usually a little tougher just generally to seasonality issues. There's a lot of items that get paid sort of in the front half of the year that then they build up on the balance sheet, sort of on the liability side throughout the back half of the year. So I think the lion's share of any kind of working capital build is behind us. We may increase working capital over the back half of the year, another maybe $20 million, but I don't -- we've bumped it up year-to-date by about $140 million. So I think sort of flat to that $20 million number is probably where we see the rest of the year going.

That's helpful. And second question is on Colombia. Certainly, the market seems like there's a bit more uncertainty there given the political regime and you did talk about a little bit of standby time for rate down there. Just curious if those 2 things are at all related and what you're seeing more broadly for the Colombia market?

Yes. So really pleased with the performance of our team in Colombia. I'll start out and just address the standby time. It's just part of the drilling program that we have with some of the customers. There are times when it breaks between pads. And we do have some standby time, but that's just part of the course of normal operation down there. Nothing related to any change in the political climate. What we're seeing so far from the elections is basically nothing has changed for us in what we do. And our rigs down in Colombia today are drilling for gas that service the utilities in Colombia. And we still have drilling programs with the various customers that we have. We have a number of different customers. It's not just one. And all these customers are signed up with contracts to service the utilities in various parts of the country. And so we don't anticipate any change to our drilling programs just because of the nature of what we're doing and the use of that production.

And maybe I'll sneak one more in. Certainly talk a lot about utilization for Tier 1 super-spec rigs in the market and operators are clearly focused on efficiencies throughout operations and drilling. But curious if you think that there is a point where we start to go with operators accepting less efficient rigs as opposed to paying for contracted upgrades? Like do you think there's a point where that starts to happen or not so much?

I think it's just kind of a low probability. And there may be a few operators out there that say, well, I'll go get a rig that's not a Tier 1 super-spec class, but that's generally not our customer. And when we look at our customer base, we see increasing activity.

Showing no further questions, I'll now turn the call back over to Andy Hendricks for any closing remarks.

Once again, I'd just like to thank everybody at Patterson-UTI, and thanks to everybody who joined us this morning. We appreciate all the hard work that our people in the field are doing, and we know everybody is busy and just wanted to say thanks.

And that does conclude today's conference. You may now disconnect.