Patterson-UTI Energy, Inc. (PTEN) Earnings Call Transcript & Summary

Good afternoon. We're going to keep things moving. Again, Arun Jayaram from JPMorgan's oilfield services and E&P research team. Excited to have Patterson-UTI to present today. Patterson is one of the largest global land drillers with a focus on the North American market. I'm delighted to have CEO, Andy Hendricks here for a fireside chat. Before beginning our discussion this afternoon, Andy, I thought I'd turn it over to you to maybe provide some general thoughts on the company. I have a lot of journalists in the audience this week. And so maybe you could give a sense of the company and the asset base and just your overall business model.

Sure. Thanks. It's good to be here. This is a good conference this week. This is a really good turnout. And I am bullish and I am upbeat on what's happening in contract drilling and oilfield services. So I'll start with that. So Patterson-UTI is 1 of the largest onshore drilling contractors in the world, actually. We operate 124 drilling rigs today. We have a number of other rigs in our fleet as well that we'll talk about through this afternoon and rigs that we'll continue to reactivate and upgrade as activity continues to improve in the U.S. We're also in pressure pumping. And we've been in pressure pumping since 1980. We were the first hydraulic fracturing company to fracture the Marcellus Shale way back in the day. And so we've been in this business for a long time. We know it well. We've got a good customer base that has a strong overlap with our contract drilling business, and we're very pleased with how that business is performing. We acquired a directional drilling company a little over 5 years ago, and we're the second or third largest directional drilling company in the U.S. onshore space. We also branched out into Colombia into contract drilling last year when we acquired Pioneer Energy Services and really pleased with how that acquisition went. The rigs we added in the U.S. and then adding Colombia as well. So upbeat about the market, upbeat about how the businesses are performing in all the sectors that we work in. And so yes, why don't we jump into some of this.

Yes. Let's start with the land segment. Andy, this has been one of the fastest, most pronounced rig count recoveries we've seen in the modern history of shale. And I was wondering if you could talk about Patterson's strategy to extract value and what's your playbook this cycle?

So 2020 started a downturn that was the worst on record in our sector. And so yes, the increases have been some of the fastest, but the downturn was one of the fastest as well. And we're seeing a good rebound out of that. When you look at Patterson-UTI and the different businesses we're in, our activity started improving in pressure pumping and hydraulic fracturing, even before drilling early in '21. And pricing started to move up quickly beginning in February. February 21 was the first time we saw some just organic price increases in pressure pumping, and it's been moving up ever since. And then a few months after that, you saw drilling activity in the U.S. start to move up and then pricing started to move up quickly with drilling. Drilling has been interesting because the pricing and drilling has never moved faster than it has over the last 6 to 9 months. We said at the call last October, that the leading-edge day rate for what we refer to as a Tier 1 super-spec rig was in the low 20s. And then we got to the February call, and I had to tell everybody it's in the mid-20s. And then at the April call, I had to tell everybody it's in the upper 20s. And then once you add on drill pipe, ancillary services, forklifts, other rental equipment that we do, you're well into the 30s. And so the pricing power that we've had in contract drilling has never been stronger.

Great. The rig count has recovered into the -- approaching the mid-7s now. What's your thought on the pace of rig count growth over the back half of the year and as we enter the important 2023 budget cycle.

So we called out at the last call in April that we're already in discussions with operators to put out rigs in 2023. And so what I think the profile of the activity increases looks like is you've seen a fast increase in the first half of this year. You're going to continue to see an activity increase in the second half, not at the same pace. But then when we get to '23, I think you're going to see a step up in activity. And when we get to the July earnings call, we'll give everybody more color on that because it's an interesting situation where we're already in discussions for the next year. That usually doesn't happen until the fall when E&Ps get into their budget cycle. But E&Ps are concerned enough about the availability of drilling rigs for next year. And also, they're having to plan ahead. They have constraints around casing and tubulars and so they're having to plan all this in advance, and they're already talking to us about the drilling rigs. So I think by the time we get to the July earnings call, we're going to have more color on what we think our rig count is going to do, and that will kind of help you understand what the market is going to do as well.

Great. And as we think about kind of the customer base, the privates have been leading the recovery and activity on our math, I think they've added around 70% of the rigs since the bottom of the rig count around July of 2020. Talk to us about your mix of customers and kind of some of the pros and cons of working with maybe a higher mix of private versus public.

So we work for everybody, from the smallest privates that you've never heard of, to large privates that you've never heard of, to the large independents that are publicly traded in the major oil companies that you buy gas from. And we have key customers in all those different sectors. What you've seen in our own rig count kind of mirrors what you just described where you've seen our own rig count more weighted to the privates, but that's because the privates have really kind of been the first movers in the industry coming out of the '20 downturn and through '21. And then you've had large independents start to kick in at the end of '21. But the large international major oil companies have really been kind of slow to get started in this area, and you haven't seen them really increase our activity, and that's what's going to happen in '23.

And then you mentioned how you're seeing your customers engage with you a little bit earlier as they think about 2023. Are you seeing -- do you expect this mix to change of 7 out of 10 rigs being added by the privates? Or do you expect there to see a little bit more rig adds by the publics.

I think the rig adds by the public really depends on the investor base. And does the investor base of the public E&Ps allow them to grow like the privates have. The privates don't have to answer to anybody but themselves and whatever shareholder base they have, and they've been growing. And the public E&Ps have been constrained because investors have wanted them to constrain their capital. And I think that that's really the right answer for the industry overall. It has actually changed the structure of oil pricing, oil and gas production around the world because for the last 10 years, we all understand that when prices start to move up, U.S. producers ramped up activity. Production was too high globally because of U.S. producers and oil came crashing back down. So we've all been through these multiple cycles over the last decade, and things have structurally changed. So it will really depend on the investor base of the public companies and do investors allow the U.S. public E&Ps to move more of their free cash flow into CapEx for growth.

Yes. Andy, can you give us an update on Patterson's kind of rig activity in the field today. Around how many rigs are you working? And I'll have a follow-up to that.

Yes. So we're operating -- we have a little over 180 rigs total fleet. We're operating 124 rigs in the U.S. and 6 rigs down in Colombia today. So that's where we are today, primarily Tier 1 super-spec rigs.

And if demand continues to rise, could you give the audience a sense of how many super-spec idled rigs that you have in your portfolio?

Yes. I don't have the chart in front of me, but we still have a large number of either super-spec or just AC high-spec rigs, approximately 70 that could be upgraded to be Tier 1 super spec. And because we have 70 because our good friends over at H&P have a large number of rigs and some at Nabors. There's still a large number of rigs that can be upgraded from either high spec to super spec or into that Tier 1 super-spec category, which means there's no visibility on new builds. We're not talking about it. We have no visibility that's going to happen in this cycle. There's enough rigs out there that can be upgraded for better economics than just building a new rig. And it's very different from, say, that period of 2010 to 2014 when we were all building a lot of rigs. That was a time when the whole industry was going through a transition from the older SCR electricals to the new AC software-controlled rigs, and so that really facilitated the new build cycle. Our fleet is all AC software controlled. And now it's just structural changes on the rig. And we can do that a lot more economical just with upgrades. There's no reason to build new rigs.

And then as you think about -- you mentioned up to 70 kind of upgrade candidates within your fleet. Could you give us a sense of reactivation cost for the next 10 and 20 rigs in your portfolio?

So it really depends on what E&Ps want. We have a little over 20 rigs that we can do some simple upgrades that cost $2 million to $3 million. After that, we'll get into rigs that were built in around 2010 to 2012 time frame, and that may cost $15 million to do that. If we have to spend $15 million or more to upgrade a rig, it's going to come with a term contract. And we're going to completely derisk that capital investment. We may even get some cash upfront from some of the E&Ps because the market has changed, the market is tight. We're the ones more in control of the negotiations than we have been for the last 5 or 6 years. And so we want to be able to derisk this. We want to be able to maximize the return that we get out of this. And if we're going to spend that kind of capital in that range, it's going to come with a term contract over 3 or 4 years.

Okay. You touched on this earlier, but where would you peg leading-edge kind of pricing today? And are you having -- are you seeing any shift in the market for E&Ps shifting to a bit more term work?

I'll work backwards to that question. The E&Ps are struggling to get their head around this market. A lot of them haven't seen it. This market hasn't been this tight in terms of drilling rigs since 2013 and '14. And some of the people that are in the drilling departments at the E&Ps weren't in a position back then to even renegotiating. So they haven't seen this type of market. They haven't been in a market where they didn't have any negotiating leverage. And so they're still trying to understand it. And it's still a challenge for them, but the pricing is moving up. I actually had I had 1 E&P call me about a month or so ago, and he wasn't involved in the negotiations in his company, but his team gave him some feedback on us, and he called them and he said, "Look, you guys are being immoral and unethical." I said, "What are you talking about?" So I said, "let me see what's going on, and I'll call you back." So I called my guys and they said, "Look, they called, they asked for a price, said they need a rig. We gave them the price. We said, let us know because we have other E&Ps." And then they just kind of goes to this for about 10 days and wouldn't return the call, which means they didn't like the price. They're calling around. They're trying to find a rig at a better rate. When they finally call them back, the rig was gone. And the next rig costs more. That's what's happening in today's market. And E&Ps are struggling to get their head around how fast this is moving.

Okay. If the leading edge now is moving into the low 30s. Give us a sense of on the cost structure side, what are your average cost -- daily cost per rig day?

Yes. So with leading edge plus everything in, in the low 30s, it sounds like a lot. It sounds like it's a lot higher than it used to be, but it's not really because costs have moved up since that 2013, '14 time frame. So today, our cost in terms of OpEx to run the rig is about 16.5% in that range. And that's primarily personnel. We've had to give wage increases over the last year for the personnel. And then the rest is consumables in terms of OpEx on the rig. But if you think about it in terms of margin and you go back to 2014 when we hit a peak, and we put this in the presentation that we put out yesterday morning. Our margins at the peak in 2014 for an AC high-spec rig were a little over $13,000 a day. And in today's market, while we may be at leading-edge day rate of $30,000 and with our average day rate, our average margin at the end of last quarter was just a little over $7,000. So $7,000 today versus $13,000 on average back in 2014, tells you we still have a long way to go, and we still have a lot of upside.

Perhaps as you think about that path, if you're at $7,000 today, do you get the sense is that $13,000 for the fleet is an achievable, absent any like collapse in the broader market?

I think the real question is how long does this cycle go on? Because if this is truly a multiyear up cycle for more than a couple of years, then we'll pass through that number. The rig market is that tight. Three companies control the remaining AC super-spec rigs that aren't working today.

Great. In terms of customer preference, one of the reasons why Patterson's activity trends have been robust is just your investments in walking systems. And so there's -- as you know, there are different flavors of super-spec rigs and maybe give us a sense of where you're seeing the strongest demand today.

So the super-spec rig has evolved from the high spec to the super spec to the Tier 1 super spec over the last few years. And Mike Drickamer is here. He gets a lot of the credit for defining the -- what is a Tier 1 super-spec rig. And it starts with a couple of things. It has to be pad-capable. And when we say pad-capable, we mean the ability for the rig to move and walk around the rig or their pad. And the walking system is the preferred way to do that. And Mike Holcomb, our Head of Drilling and he gets the credit for bringing the first walking system to Lower 48 on a drilling rig back in 2006 in Colorado and the Piceance. And everybody has been following Mike with the exception of one company, who is one of the late followers. And so that ability to be pad capable and have the draw works lifted up. So you've got all the clearance under the rig structurally is the optimum drilling rig. And we've been building that rig since 2012.

Okay. Let's shift gears and talk a little bit about your pressure pumping business. Can you just provide a little bit of color to the buy side and how many fleets that you're working today? And what is your total horsepower that you could put back in the field?

So we've been in this business for a long time since 1980. We're good at it. It's been a great part of our portfolio over the years. They're doing a great job today. Before the COVID downturn, we were working 10 spreads. 2 years later here, 2.5 years later, we're working 12 spreads and higher horsepower per spread. So the intensity of the works increased. And so we actually have more pumps deployed now than we did even before the downturn started. And so the team is doing a great job. We're working 12 spreads. The majority of these spreads run natural gas as the primary fuel. We were one of the first companies to do that, and we've always been a leader in that space in terms of natural gas-powered frac. And we're also full service. We do some mining as well. We primarily work in the Northeast U.S. and in Texas, and our teams are doing a great job. Now one of the things we've said is as we've grown this and we went all the way down to 4 spreads in the downturn, we've grown it back up to 12. And we said that this year, we're just going to stop at 12. That doesn't mean that there's not demand. There's still demand for frac spreads out there, but the right answer for Patterson-UTI is to stop at 12 for now and push pricing wherever we can. Pressure pumping is not like drilling where we get some term contracts. We do pricing agreements, a lot of them with 30-day outs, and that 30 days gives us an opportunity to walk back into a customer's office when the market is moving up and say, "All right, we need to talk about the price because stage prices are moving up." So the right answer for us this year is stop at 12 spreads and just push pricing where we can and improve the margin.

And in terms of the dual fuel capabilities, how many of those 12 spreads can use natural gas?

Yes, it's the majority. We're working today. 7 of the spreads are running out of the 12 with natural gas as the primary fuel. In fact, we were just visiting one yesterday in Ohio.

Okay. Great. And then are there any plans to do any more conversions of your fleet in terms of the engines?

We might. It's really operator-dependent. Not every operator needs natural gas as a primary fuel. Some operators are working in areas where they can't get large volumes of natural gas piped in. It was interesting that the project that we saw yesterday to give you an idea of how it works is they were close to the Williams gas pipeline over in Ohio. So with 20 pumps working on location, which is turning into the norm, they need large volumes of clean natural gas. So they're pulling natural gas straight off of the Williams natural gas pipeline, run it through in a filter and scrubber system at the well site, and then reroute it into 20 of the engines there at the well site, but it's large volumes of gas. And then when they produce again, they produce back into that same Williams pipeline. But you got to have clean gas and you got to have large volumes. So it depends on where you are. When you're in the Permian, you don't always have access to gas at that volume.

And we have seen, based on our work, a really tight market for frac. You mentioned that you have 12 working -- you're seeing more demand than to keep that working. But what are you seeing in terms of margins? We like to think about an EBITDA per fleet basis. But what are you seeing on the margin side of that business?

Yes. So we're working 12 spreads right now. And at the leading edge, our equivalent adjusted EBITDA compared to everybody else's is running around $20 million per spread on an annualized basis. And I think there's upside on that, there's upside for us to push up some of the pricing that's not at leading edge on the current fleet. It doesn't mean we won't activate another spread next year, but it was the right answer for us this year just to stop at 12. But I think that what you're going to find in pressure pumping is the market is extremely tight and it's an economic tightness on the part of the pressure pumpers. It doesn't really matter if it's us or NexTier or Liberty or whoever it is. The next spread that comes out is going to require a large amount of CapEx to get it going. And to be able to do that, that pricing at that leading edge has to move up again. And when that leading edge moves up, the other spreads move up as well. So we'll just have to wait and see what the market looks like. There's going to be more demand. You'll see more spreads activated, may or may not be the right answer for Patterson-UTI, but we'll wait and see what next year looks like for that.

Let's talk about financials. I think our model for 2022 for the company is around $500 million, plus or minus, of EBITDA, $650 million next year. Give us -- again, I don't want to specifically ask you on guidance and things like that, but just how you're feeling about Patterson's -- about the consensus view that's out there.

Early this year, as a company, we've done something we've never did. We came out in the press release and said what we thought we were going to do for EBITDA for the year, and we've never done that before. But we really had a sense that the market did not understand how fast business was improving and how fast pricing was going up. So when we put out the press release for the full year last year and we gave forward guidance for '22 that said we were going to do at least $450 million of EBITDA this year. Well, then when we came out with the next press release in April, we said we're now going to do at least $500 million. So it continues to move up and pricing is continuing to move up, and we may give you an update in July.

Okay. Good stuff. Question just on the Pioneer acquisition. Thoughts on Colombia. Is this an area that you want to invest more on in terms of growth CapEx?

So the Pioneer acquisition was something that we had worked on for a long time. We've followed the company. We knew the management team, we knew the assets. We first tried to do this all the way back in 2015. So it gives you an idea of how long it takes to put some of these deals together sometimes. They look good and easy on an Excel spreadsheet. But in real life, they can be a lot more challenging. So we did the acquisition last year. And to give you a little bit of background on it, which is all in the filings, but started during COVID, they went through a bankruptcy. They assigned a new Chairman. I called the Chairman, of course, we're in the middle of COVID. And so we met for coffee under a tree outside in Houston and began to talk about it in November of '21. They had -- as a Board, they had to run a process. It involved a number of bankers, other companies. We were eventually successful in the process. But we didn't start off wanting to buy the whole company, we were really interested in their drilling businesses, the U.S. drilling and the Columbia drilling. But they also had 2 other businesses, a wireline company and also a well service rig business. But it was clear because of the complexity on the debt side of the deal and trying to get it done that the only way it's going to happen if somebody stepped up and bought the whole thing. So we did, we took the execution risk to do that. We ended up buying, for instance, the U.S. drilling rigs at the time were probably valued around $11 million per rig. And an equivalent rig for us at the time of the portfolio was probably valued at around $13 million per rig. So we got what we thought were equivalent assets in the U.S. at a discount, which is really our objective in that process. And so we closed on that at the end of September last year. And then by the end of the year, we had sold off the wireline business and the workover rig business. Now if I say it fast, it's easy, but it's not. It's -- when you look at what HR has to deal with, onboarding over 800 people and then off-boarding over 400 people, so everybody gets a paycheck and has their benefits covered, it's a big challenge, legal, accounting, finance, all these pieces are pretty tough. And so -- but the teams did a great job, and we got all that done before the calendar year last year. So back to the Columbia drilling. Really happy with that. It's something that we've watched Pioneer Energy Services grow. It's a 15-year-old business. They're well entrenched in Colombia with good customers down there. They're drilling for natural gas, which is a little bit different from oil. They're not actually doing exploration, they're doing infield drilling in existing fields. So it doesn't kind of fall under the remit of the new president where he says no more new exploration. And so they're drilling natural gas fields and just continuing to fill the utility lines down there. So our estimation so far is stay busy in Colombia, probably even pick up another rig down in Colombia. In terms of a jumping off point to other international markets, certainly, it's a good place to start in Latin America. Colombia is a great country to do business in, it's relatively safe these days. You've got good financial infrastructure. You can convert to U.S. dollars to get cash out, and you've got a number of good customers to work for, not just Ecopetrol, but you've got some other public companies down there, too. We may move into Ecuador. We'll see. That's another good opportunity in terms of oil drilling in the southern part of Ecuador. But I think after that, the other countries in Latin America, at least from a risk profile, get a little more challenging. Everybody tells Argentina and the Bakken [indiscernible], and I used to go down there years ago to deal with a different business at that time. But Argentina has challenges, and you can't convert to U.S. dollars to get your money out. And so risking, putting large assets in Argentina without being able to extract dollars is a huge risk these days.

Yes. Talk to Scott Sheffield, if you're ever thinking about investing in Argentina. Let's talk a little bit about CapEx, $350 million is your target this year. What kind of investment opportunities are you seeing in terms of deploying CapEx? And is it too early to give a read on next year?

Yes. So we've been holding our CapEx pretty steady this year even though we've talked about some EBITDA increases. So we're going to hold it $350 million. It's primarily maintenance with a little bit of growth in pressure pumping in terms of dual fuel systems that we added this year and then more growth in drilling as we do some of the upgrades and start some of the preorders. We're currently in discussions for rigs that may go out next year. Those aren't final. We don't know exactly the specifications, but there's a good chance that we might have to add a little bit of CapEx this year just for the preorders for '23. But any of that additional CapEx, especially if it's a large upgrade on a rig, it's going to get covered with the term contract.

Okay. Just a couple of minutes left. Can you talk about Patterson's technology portfolio footprint?

Really excited about what we have these days. We touch a lot of different aspects of drilling and completions. It's part of what we updated in the slide deck. I think we've always had the opportunity to do a better job explaining all the different aspects of where we touch the E&P spend. But in terms of the E&P spend and drilling and completions, we touch about 50% of what they can potentially spend at the well site across drilling rigs, across cementing, across directional drilling, on the drilling side, rental equipment on side, on completions, hydraulic fracturing, data analytics, rental equipment on that side as well. So there's a number of areas that we do that. In terms of the technology, it's exciting to watch how our portfolio connects together and that continues to evolve because we have the drilling rig, we have directional drilling, and we have a data analytics system called Superior QC that actually does cloud-based computing to forecast where you need to go to steer well and do well placement and that can control the drilling rig, that can control what we do with the downhole tools and directional drilling. We work -- we continue to work and improve automation systems on the drilling rigs to match up and pair up with those data analytics. We've evolved remote operations in our directional drilling business. When we're running a directional drilling business, the measurement portion of that business, which used to take 2 people at the well site only takes 1 because we managed the nighttime hours through remote operations from our office in Houston. And so we continue to move the bar on technology and really excited about how it links together all the different businesses in Patterson-UTI.

And my last question is, Andy, next year, in particular, you could have -- be generating a significant amount of free cash flow. And how are you thinking about balancing more growth within the business towards maybe a shareholder return type policy?

Any growth that we look at in the business going forward has to be tempered with good returns and protection on the investment to manage the risk. And so for instance, as I've said multiple times today, any major upgrade on a drilling rig is going to have to come with a term contract. So there could be growth investment in CapEx next year. But you can count on us protecting that growth if it's large with a term contract and making sure we're getting a good return on those dollars because that's the type of market we're in and that's what we can ask for. We are going to produce what we believe is a significant amount of cash next year on EBITDA minus CapEx. And there will be CapEx used for maintenance. There will be a little bit of CapEx used for growth. And we'll also probably start to hold more cash, and that will be for future debt paydown. Our debt profile is good. If you look at the projections on our '22 numbers at the end of this year, it puts our debt to EBITDA at about 1.5%. So there's nothing wrong with our debt, and we have public debt that's not due till 28, but it's not worth paying off yet either. So we'll probably start to accumulate some cash on the balance sheet for future paydown on the debt. But then after that, we'll look at returning cash to shareholders. That's something the company has done a really good job of over the years. If you look at the last decade, we've given back $1 billion to shareholders, mostly through buybacks, but also through dividends, and we'll continue to look at ways to give cash back to shareholders this year and next year.

Great, Andy. We're out of time. Thanks for your time today and appreciate your support of the conference.

Thanks for having me. Good to see you.