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

All right. Good morning, everyone. So kicking off our North America-focused names. We have Andy Hendricks, CEO of Patterson-UTI, obviously looks a little bit different now after the merger with NexTier and Ulterra. So we're going to do a little fireside chat here. Andy?

Thanks for having me today. Good to be here.

Great. So, let's just start off there. Fresh off the closing of the merger of Ulterra and NexTier, how are you thinking about the deal as it evolved during the last 3 months when it first announced?

We're really excited about this merger. It really changes the shape of the company. To give you a little bit of background, I've explained this to a few of you already, but we've kind of had a challenge at Patterson-UTI. We were a plus $5 million company back in 2013 and '14. We've worked hard over the years with various mergers, acquisitions, organic growth of technology, build out of systems to try to get back to where we were, and we just weren't quite getting there, and so that was one of the challenges that we had. We had another challenge in that our Universal Pressure Pumping division does a great job. And even though with some of the acquisitions and some of the investments that we made, we weren't as big as some of the others that were out there, and we had to make some strategic decisions around what to do with that. And when you look at what NexTier has done with not just hydraulic fracturing, but how they integrated vertically hydraulic fracturing, wireline, the NexMile logistics systems for transporting everything, the natural gas power systems for [ gushing ] CNG, delivering it to wellsite, blending it to the wellsite with fuel gas, and what that's done to their efficiencies and how well that they can perform for the E&Ps, that was just fantastic. And we could certainly see the synergies in putting our 12 spreads into the NexTier, and then putting those verticals on that. And when you combine all the potential synergies, NexTier was just a great fit for us.

Perfect. So that's perfect dovetail to my next question on those synergies. So maybe just walk us through how you plan to reach the $200 million of deal synergies announced in -- I think that was over 18 months? I know it's a revenue and a cost perspective. I know -- and you will be leading the charge there. Just on the rest. And then on the revenue side, do you have the assets you need to fully NexTier-ize Patterson, please?

Yes. And as you mentioned, Kenny Pucheu is the CFO for NexTier. He's going to be the Chief Integration -- or he is the Chief Integration Officer now that we have closed for Patterson-UTI, so happy to have him there leading that effort. And of course, Matt Gillard is staying on, and he's going to be running all the well completions with Universal going into NexTier. When you think about the synergies, think about it in terms of 3 buckets, and let's start with the revenue because that's the one we're really excited about. So about 1/3 of that $200 million is us just being able to put the vertical integration of these other systems, whether it's the wireline, the NexMile logistics, natural gas systems on top of the 12 spreads that Patterson-UTI was historically operating. And so we think that will take about a year or so to get that in place, but that's huge for both not just in additional revenue, but in additional efficiency and productivity of each of those spreads. We recognize this at Patterson-UTI that you can have a $50 million wireline crew -- or sorry, you can have a $50 million frac crew waiting on a $1 million wireline crew, and if you don't control the wireline, that puts you in a bad spot. But when you control the wireline operation and you control the other things like logistics, you make sure the sand is there, you make sure the chemical is there, and then natural gas blending, where you can maximize the uptake of natural gas and the systems to displace diesel and get the maximum cost savings for the E&P, those all play into things. And so we tried to buy a wireline company over the last 5 years and we couldn't get to a deal that made sense, that would have improved our own efficiencies. But this is a great fit with the Patterson-UTI and NexTier coming together there for that. You've got another bucket of synergies, which is really another 1/3, which is your traditional SG&A. Some of the costs, insurance costs, banking costs, all those kind of fees that you have, organizational costs. And then the other bucket is just really around supply chain. I mean, think about the breadth of what we buy across all of Patterson-UTI. Think about all the [indiscernible], for instance, that we purchased, for all the drilling rigs we operate, for all the pressure pumping systems, for all the cementing systems. And so there's just a number of things there that gives us more leverage on that supply chain. So that all adds up to at least $200 million of synergies on an annualized basis, and we expect to realize that in about 18 months in total.

Great. That's helpful. And maybe just, do you believe that you have the asset base in place toward integrating the Patterson and NexTier fleets together? Or do you think you'll need some additional purchases of wireline or any other assets?

There could be some additional purchases. But for instance, NexTier's wireline business is the second largest wireline business in the United States. I mean, it's a formidable force within that sector of oilfield services. We'll probably need to add some additional pieces there, but we're talking $1 million per wireline package, including a truck. So relative to a frac spread or a drilling rig, this is, I'll say, de minimis. It's not a big number in terms of capital.

Great. Okay. So I also want to make sure we talk about Ulterra too, that's your other acquisition. I guess, how is that gone for the first part of the year versus expectations? And then just overall, on the integration strategy that you have now between drilling and completions now that you have the drilling rig, the drill bit and the first drilling, so how does Ulterra really round that out?

So Ulterra is a drill bit company that apparently, a lot of people didn't know who they were when we announced that we were acquiring Ulterra. We knew who they were. We tried to buy them 5 years ago back in 2018. We got outbid by 2 private equity shops at the time. Blackstone was a successful bidder in that, and they did a great job managing that company over the last 5 years. They've actually grown EBITDA, grown the international presence there, but they're ready to move it on out of their portfolio, and we actually started talking to them a year ago this week, and these things take time to work out and we just closed on it 2 weeks ago. But excited to have them in our portfolio. And some people say, well, why drill bit, with everything else that you have? We actually have some influence over which drill bit gets picked up at a wellsite. Sure, the E&P buys the drill bits, the drilling engineer is going to make decisions on which drill bit they want to buy, and they're going to have a selection of them at the wellsite. But if you go out to a drilling rig, you're going to see a pallet on the ground. There's going to be a number of drill bits backed up on that pallet. Some of them might be from a Schlumberger or from NOV or from Halliburton, from Baker or Ulterra. But we actually have some influence because the discussion happens at the wellsite sometimes about which drill that gets picked up, whether it's a surface bit for the surface hole or it's the drill bit for the curve or the drill bit for the lateral section. Because of what we do, either in contract drilling or directional drilling, we're part of that discussion, but why not participate in that and not just influence it.

Great. I think another big piece of the NexTier and the Ulterra, you just -- you've allocated a lot of airtime around this data theme when you announced both of these deals. Just can you help us and investors understand the data strategy for Patterson going forward? And how we should see it show up in your financials?

Data has been a big part of what we do for years now. We've done a lot of work internally to grow what we've had at Patterson-UTI historically on our data system and to learn how to use data to better perform for -- with E&Ps. It kind of started out in the early systems, okay, let's track and try to really understand how things are performing on the surface with equipment to maintain uptime. Well, that evolved over time to, okay, let's see what we can do to improve what we're doing downhole as well, and so those are the types of systems and evolution that we've done. When it comes to our directional drilling, we have remote operations where a lot of the night shift is run remotely from Houston, and some of the number of pieces that we've done and built out organically at Patterson-UTI. NexTier has done very similar, and so NexTier has built the NexHub solution for data analytics. They're monitoring health of equipment, they've shown where they can improve the uptime of engines, transmissions, fluid ins, things like that by watching the 1,000 sensors that you can pull in from a frac spread, so they've done a really good job at that. And then when you look at Ulterra and what they've got in data analytics, they actually track 70% to 80% of every bit that goes in every well across the United States and Canada. This is a huge amount of information, and we're not getting into the E&P's remit of subsurface, reservoir, what is the geophysical structure of the basin look like. But when you look at operational data from drill bit, your drilling rigs, your directional drilling through wireline, netting plugs, perforating, hydraulic fracturing, all those operational pieces will have the broadest set of operational data of any oilfield services company across the U.S. And what that does, it allows us to look at how we are performing and be more efficient and more productive for the E&Ps over time.

Great. That's helpful. All right. So you guys put out an investor deck yesterday morning, so let's talk about that. Obviously, the Page 1 there was the activity outlook...

You always wait for your copy.

Yes, always. I love it. You took -- you preempted some of my questions here, but that's okay. So you did -- I think you quoted 48 rigs starting to reactivate, I believe, in October for fourth quarter, rig starting in October and an additional rig for 2024. So maybe just walk us through that? What gets you to 4? What gets you to 8? Is it customer type? Is it basin type? Just maybe a broader view on this deck that you guys put out.

Yes. When we did the last earnings call, we said, hey, look, the macro is strong going forward. There's some high-level discussions happening. And then this week, we were able to file the presentation and say, look, we've signed contracts for 4 drilling rigs that are starting in the fourth quarter. We're in discussions on another 4, that may turn into contracts either for the fourth quarter or the first quarter next year, and we're in discussions for rigs going out in various months and quarters in 2024. This is really the macro driving this on where commodity prices are, and the 4 that we signed contracts for and the other 4 we're in discussions on, those are a mixture of oil, a mixture of gas, a mixture of publics, a mixture of privates, everybody has wanted to jump back in just looking at where commodities are. Oil, WTIs, plus or minus $80. It's got some relative stability again. And then natural gas, natural gas was a driver for all the softening that we really saw in 2023. And if you look at the forward strip, you're already above $350 in December and plus that going into 2024. And a number of our customers that work in that Haynesville area were feeding into the Henry Hub from South Texas or from Oklahoma, they need $275 or greater. Well, here we are in December at $350 and moving higher in '24. So the macro is driving the commodity prices. And then we haven't even talked about LNG. And I think when you look at natural gas and the increasing activity in natural gas, think of it in terms of 2 different events. I think that what you're going to see at the end of this year and going into next year is an increasing level of activity based on where the commodity strip is. But then 2025, there's huge amounts of LNG that are expected to be exported or start to be exported, and so the end of '24 will be another event to start to build well inventory in natural gas as well.

So the 4 rigs that you placed on contract that are starting up, can you talk about the term on those? Is that going to be short term? Is that a year? Is that 2 years? Has the term changed at all?

So there's a mix of the term in those contracts. We have come out and said, look, leading edge at this point of where we are in the softening of the market is kind of in the mid-30s, maybe to low 30s but that's still a pretty good number. It was in the upper 30s at the beginning of the year. I think there was this huge fear out there that for drilling contractors like ourselves, that there's going to be a big price collapse, and it just really didn't happen. So our pricing is in good shape, and I think you'll see pricing start to inch up as that rig activity for our super-spec rigs starts to move up as well.

So I looked at your website the other day, and in the presentation, it was at 116 but I think you're at 117 now. You feel comfortable with that 116 mark as a bottom as you've had these 4 -- at least these 4 rigs?

There might be some day-to-day movement in there, but I mean, hey, we got 4 rigs that are going out for sure in the fourth quarter. So yes, we're somewhere around the bottom right now.

And then last question on the rig count. Industry rig count, whether you think we can get up to 700 by the end of next year? Or do you think we'll stay in this range around 650?

Yes. I'm putting stake in the ground, Baker Hughes rig count. We're going to be over 700 by the end of '24 based on commodity prices in oil, commodity prices, where they are in gas at the end of this year, early next year and then what you need to do to feed the LNG train going into '25.

All right. I like it. Let's move over to completion. So again, in the presentation, you talked about completions activity improving in the fourth quarter, which I thought was pretty surprising, just given some of the commentary I heard from NexTier before they joined with you guys and for Liberty, talk about maybe some -- and then ProPetro talked about some activity softening up through the fourth quarter. That 1 quarter lag in rig count but it seems like maybe that oil, where it is today, that's going to firm up. Can you maybe delineate legacy PTEN, NexTier spot versus dedicated? What's causing you to believe that you'll see improvement into the fourth quarter for frac?

Yes, a few different things. So on legacy Patterson-UTI with our Universal division that's merging into NexTier, we had dropped to 11, but we knew we were going back to 12 in the fourth quarter. We're actually carrying the people for that 12 crew, so the margins weren't as good as they might have been historically in the third, but that's just because we were carrying the fixed cost because we knew we need the people in the fourth quarter. When you look at the rig count moving up, our rigs are starting to go to work in October. So I think you're going to see overall with the combined entities next year, Universal, all merged together as NexTier well completions. I think you're going to see that activity picking up around the end of the fourth quarter. The other piece of that is we get a lot of questions about what do we think seasonality is going to do this year? Sometimes, seasonality is based on what's happening with commodity prices, and commodity prices are in a good spot. So I don't think we're going to see a lot of seasonality or tail off of activity at the end of the fourth quarter this year.

Great. And then pricing for frac as well is yet another big debate. I think similar for the rigs that the low was a bit higher than what people originally anticipated when seeing that spot market was coming in weaker. We thought it was going to clear, the dedicated market really didn't happen. Legacy Patterson is a bit more spot, NexTier is a bit more dedicated. I guess what are you seeing now from a blended price perspective in frac?

I think the good news is with all this consolidation that's happened over the last 3 to 4 years in this completion space, you've seen more discipline and more supportive on the pricing side. So again, there's a sheer price collapse with the softening in the market this year, and it just really didn't happen. And you look at what NexTier has done, they've done a great job. Their dedicated percentage is maybe around 70% to 80%, and so that pricing really didn't move for them. Their activities held up really well. And as we combine the Universal spreads into that, it's going to stay roughly about this same in terms of percentage. And so we just -- I'm very positive about where this market is. It's just become very constructive. With Universal and NexTier coming together as well, that's just another example of some consolidation in the market that continues to bolster the market in terms of pricing. And us being able to do this on September 1, even before the E&Ps really get into some of the season of negotiating with us, it is positive for us and positive for the market to have these 2 companies already put together. So I just think that market has just become a lot more constructive than it has historically.

You feel that you'll have a transition from legacy Patterson fleets moving from that spot market into the dedicated market, and maybe this goes with a question of recapitalization of the fleet. I know you announced, I think, it was 10 dual fuel fleets. I'm sure that's a big part of the strategy is to increase the quality of the legacy Patterson up to more of that NexTier, is that anything that will drive going more from spot to the dedicated model?

Well, our legacy frac fleets were really about the same percentage of primarily natural gas with the dual fuel as the NexTier, so they were in good shape from that standpoint. And when we did see the slowdown this year from the natural gas and that put pressure on all the markets around Texas, and we ended up with a little more spot work versus NexTier. But all that's going to kind of normalize as activity increases towards the end of the year, and so I expect the combined entity to have dedicated fleet at around that 70% to 80%. But as we talked before in the synergies, it's just layering on those other verticals that NexTier has that will raise the overall EBITDA per spread from that standpoint.

So just a final 1 on the completions. I mean I know you talked about legacy going from 11 to 12. Where is NexTier as far as their fleet count?

They're not really calling that out, and we're not sure we're going to call that out going forward. We're going to be the total of 3.3 million horsepower. And one of the challenges is we might be doing 1 frac spread with 22 pumps over here, and then a Sanjel frac with 40 pumps over here. So what does the spread mean today? It really is hard to define. And so just coming out and saying, hey, we're working X number of spreads, they can be talking fees depending on what kind of work they're doing. So it's kind of -- let's just stick with the 3.3 million horsepower for now.

I had to try. So North America efficiency is driving a structural change is a big theme that we're starting here, particularly from the E&Ps who just continue to keep breaking efficiency records, extending laterals, drilling faster, improving cycle times, increasing completions efficiencies. On this, optically, it sounds like, well, that just means less rigs and less frac spreads going forward, structurally in North America. Can you maybe talk about this trend? And how Patterson will capture value in this trend, if we are just in a structurally lower activity environment? Is there something that we're missing that the services side will benefit in this trend as well?

Yes. One of the things you have to bear in mind is when you're looking at these macro trends, what's really driving the data? And so when you're looking at the U.S. complete in terms of how productivity and efficiency is improving, you also have to remember that activity has gone through this bit of a softening where you've had overall rig count and activity slowdown and pumping of over 15%. And so what you're left with is actually the best wells with the highest productivity, best crews with the most efficiency. And so I think as activity starts to pick up again, some of these numbers start to normalize, too. But all that being said, it's hard to get much more efficient than we're doing right now. When you look at completions in general in that sector over the last few years, we've pushed the number of hours per day that we pump up significantly. Four years ago, it might have been 14 to 16 hours, this was a really good day on hydraulic fracturing. Now, we're at 22 hours a day. It's unlikely that we're going to go to 25 hours a day on pressure pumping. So at some point, you're going to hit the wall on that, and so I don't think you're going to get much more efficient than what we do today. Small steps, yes, but the industry has made great strides over the last 4 years now.

So is it fair to say that it's maximizing revenue per lateral foot basically from a servicing perspective where it's more stages, it's more sand downhole, it's extending laterals where you get maybe paid on the length of the well rather than just the day? Like is there just different ways that you could approach it?

Yes. And think of it in terms of service intensity, too. I think as people talk about Tier-1 and Tier-2 for the E&Ps and where their properties and their plays are. And as we get into more Tier-2, it becomes more service intensive on our side which is exactly a benefit for us at this commodity price.

So given where we are in the calendar, views around next year tend to be formed at this conference, particularly with 2024 E&P CapEx budgets. How would you delineate between service pricing on the rig and frac side, which we just went over, that seems to be holding up relatively strong, versus activity? And then consumable costs, which seems that that's going to be the deflationary tailwind for the E&Ps at OCTG, the steel [ people ] popping drill pipes. So maybe if you could break it down into those buckets? Or at least we talked about the pricing on that activity, and maybe that fuel to where E&P is today?

Yes. I think the E&P has got a big break this year, especially we don't actually buy a lot of tubulars outside of drill pipe. Casing is a huge purchase for the E&Ps. They got a break on that because last year, the mills were starting to get caught up on tubulars, and we could see a little bit of that on drill pipe as well. And so they got a big break on that. Sand, with the slowdown in activity, there's been huge breaks on sand. There's plenty of sand available today, so that's -- those are huge deflationary costs for the E&P when you look at drilling and frac and then completing wells. I think if the mills stay caught up, they still have that break going forward into '24 on steel, although activity is going to increase. I still think the E&Ps will be good state from a budgetary standpoint. What you really didn't see in '23 was deflation on the service side. We just didn't see big movements in what it took to run a wireline truck or a cementing truck or a drilling rig or frac spread. And so I think all in all, that's -- it's still positive for the E&P. Budget is still positive for our activity levels.

Is it a fair assumption to think that E&Ps control CapEx budget et cetera plus or minus down 10%? Yet on the services side, we could see increased profitability just because of those different buckets available?

I think you could. And like I said, sand and steel are some of their biggest costs. Our service pricing really hasn't moved very much, and I expect rig rates and service pricing depending inside NexTier's activity inches up. But I don't think it really has a negative impact on E&P budgets given the other breaks they got.

Great. Sounds like a win-win. Reactivation expense. I know you guys mentioned it in your deck as well, and you just touched on it. You didn't see much deflation on your side from spreads. Maybe just talk about the interplay there? If we think about rigs going back to work, trying to get to that 7 handle. What can we expect as far as reactivation expenses? And have you been able to capture any sort of deflation within the service vertical?

When we were activating rigs back in '20 and '21, we were spending at least $2 million just on the activation in some cases, and these were built into the term contracts we are signing. There might be another $5 million or $7 million in upgrades that we were doing on the rig. Well, as we slowed down this year, we do preservation on the rigs, and so it's pretty easy to restart them. These -- we were working 132 rigs back in January. We slowed down to 116, we're up at 117 now, so that's 15 rigs that can come back easy. They've only stopped working for the last few months. In some cases, some of the crews are still part of our system. And so as we work up, we do have to restaff crews, but that's $100,000 to $200,000 per rig, mostly OpEx and built into day rates. So I expect that CapEx is minimal on that because we had already spent that in the previous years.

Interesting point on the labor. I guess, maybe how have you been able to configure your crews in order to answer that call and demand if the rigs start to come back? Is it just pulling folks off of other rigs? Is it hiring? Just maybe how do you approach the labor side?

You have to remember that in our industry, we still have turnover. 80% of the people that work in Patterson-UTI work somewhere in the field on a hydraulic fracturing spread, on a cementing truck, wireline crew, drilling rig, directional drilling operations. It's still cold in North Dakota in the winter, it's still hot in Texas in the summer, and we still have turnover, and so we're constantly going through a recruiting process to bring new people in to onboard and train. Now what we've done with this market, because it's not a downturn. We've only slowed down 10% to 15% of our activity based on which of our sectors, and so all we do is just kind of back off on the recruiting and kind of let the turnover and the attrition to take care of itself as we work through this. And then as we start to ramp up next year and we'll start to increase the recruiting that we do, the onboarding and the training, and yes, those are costs on our side, but then we'll start to ramp that back up to feed the system to bring people back into the system.

Great. Capital allocation free cash was a big theme, obviously. I mean I know both Patterson and NexTier have capital frameworks in place, returning 50% of free cash flow to shareholders. Patterson had dividend buybacks, NexTier had buybacks. NexTier also gave that through cycle CapEx guide of 8% to 9% of revenue. What can we expect out of NewCo? How are you approaching the capital allocation framework with free cash flow generation and returning that back to shareholders?

So we're definitely going to stick with the 50% return of free cash flow to shareholders. As Patterson-UTI pre-merger, we were already ahead of schedule based on year-to-date, based on when we announce today, whatever metric they want to throw out there. For the dividend and the buybacks, we were already ahead of that 50%. We certainly want to continue that. We've been in a blackout period for buybacks, so we just haven't been able to do anything with the mergers that we've been doing, but that's going to come off here soon. And so we'll look at the market, we'll look at the dividend. When the new Board convenes to decide what to do with that. But I would say, based on where our stock trades, based on expectations and potential for the company, right now, it looks to make more steps to do more buybacks and do anything with the dividend and just keep the dividend where it is. So we still have a lot of potential. These businesses combined have the potential to produce a lot of free cash flow. We're going to get 50% back to the shareholders. That also gives us some cash as well to start to buy back even more debt. Our team has done a good job of picking up some debt coupons at a discount over the last year or so, and so we'll look to continue to do that and continue to deleverage at the same time giving cash back to the equity holders.

No, that's great. So we have 1.5 minutes left, and I don't want to leave out the international outlook as well. I mean, I know you guys are -- you have some fleets down in Colombia from the Pioneer acquisition, but also the Middle East sounds like it could be a growing opportunity based on the Ulterra acquisition and potentially maybe setting some rigs over there, which ties us to the U.S. market, and obviously feed into that system. So any final thoughts for us around the international outlook walk through the recent efforts on Colombia as well?

Yes. So Ulterra, 25% of their business is outside of the United States, outside of North America, in fact, and so they have a good presence over in the Middle East. They're currently building a manufacturing facility in Saudi Arabia. That will improve with what's called their in-country value, which allows them to sell more products in Saudi Arabia. It will also help them support countries in the region. They've been growing that international business fairly well over the last 5 years, and we expect further growth there just because of the -- not just the growth from overall activity in the international markets, but just the way that they continue to take share in those markets as well. And in the offshore markets, Ulterra is just starting and just scratching the surface of breaking into those markets. They've been focused on North America, Latin America, they have rebuild facilities in Colombia and Argentina as well. In terms of putting a drilling rig in the Middle East, there's always that potential. We've looked at it for the last 10 years, what makes sense for Patterson-UTI. We're certainly not going to go there with just 1 rig. We're only going to go there if it makes sense for shareholders and we can make money doing it. Otherwise, we'll just do what we're doing and continue to produce a lot of free cash flow where we are.

Great. All right, and that's all the time we have. Andy Hendricks, CEO of Patterson. Thanks for joining us.

Thanks for having me.