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 gonna 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 and the merger of equals with NexTier, how are you thinking about the deal, and as it evolved over the last three months when it was first announced?
We're really excited about this merger. It really changes the shape of the company. You know, to give you a little bit of background, I've explained this to a few of you already, but, you know, we've kind of had a challenge at Patterson-UTI. We were a +$5 billion company back in 2013 and 2014. We've worked hard over the years with various mergers, acquisitions, organic growth of technology, build out a system 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 P umping division does a great job, and even though some of the acquisitions and some of the investments that we made, you know, 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. When you look at what NexTier's done with, not just hydraulic fracturing, but how they integrated vertically, hydraulic fracturing, wireline, the, you know, the next mile logistics systems for transporting everything, the natural gas power systems for progressing CNG, delivering it to the 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.
We could certainly see the synergies in putting our 12 spreads, you know, into the next year and then putting those verticals on that. 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. That was over 18 months. I know it's a revenue and a cost perspective. I know Kenny 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 NexTierize Patterson fleet?
Yeah, and as you mentioned, Kenny Pucheu, who's the CFO for NexTier, he's gonna be the chief integration, or he is the chief integration officer now that we've closed. But for Patterson-UTI, so happy to have him there leading that effort. And of course, Matt Gillard is staying on, and he's gonna be running all the well completions with Universal going into NexTier. When you think about the synergies, think about it in terms of three buckets. So let's start with the revenue, because that's the one we're really excited about. So, you know, about a third of that $200 million is us just being able to put the vertical integration of these other systems, whether it's the wireline, you know, the next mile logistics, natural gas systems, on top of the 12 spreads that, you know, Patterson-UTI was historically operating.
So we think, you know, that'll take about a year or so to get that in place, but that's, that's huge for those. Not just in, you know, additional revenue, but in the additional efficiency and productivity of each of those spreads. We recognize this at Patterson-UTI, that, you know, you can have a $50 million wireline crew, or sorry, you can have a $50 million frack crew waiting on a $1 million wireline crew, and if you don't control the wireline, you know, that puts you in a bad spot.
But when you control the wireline operation and you control other things like logistics, you make sure the sand's there, you make sure the chemical's there, and then natural gas blending, where you can maximize, you know, the uptake of natural gas in 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 five 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, you know, with the Patterson-UTI NexTier coming together there for that. You've got another bucket of synergies, which is really another third, which is your traditional SG&A, you know, 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 lubricants, for instance, that we purchase for all the drilling rigs we operate, for all the pressure pumping systems, for all the cementing systems. And so, you know, 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 in synergies on an annualized basis. And we expect to realize that, you know, in about 18 months total.
Great. I think that's helpful. And maybe just, do you, do you believe that you have the asset base in place to work integrating the Patterson and NexTier fleets together? Do you think there'll be some additional purchases of wireline or any assets?
There could be some additional purchases. So 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, you know, you know, $1 million for a wireline package, including a truck. So relative to a frac spread or a drilling rig, this is, you know, I'll say de minimis. It's not a big number in terms of capital.
Great. Okay. So I also wanna make sure we talk about Ulterra, too. That's your other acquisitions, I guess. How has 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 pressure. 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 five years ago, back in 2018. We got outbid by two 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 five years. They've actually grown EBITDA, grown the international presence there, but they were ready to move it on out of their portfolio. We actually started talking to them a year ago this week. And, you know, 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 bits, you know, with everything else that you have?" We actually have some influence over which drill bit gets picked up at a well site. You know, 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 well site. 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 stacked 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 well site sometimes about which drill bit gets picked up, whether it's a surface bit for the surface hole, or it's a 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. So why not participate in that and not just influence it?
Great. I think another big piece of the NexTier and the Ulterra, 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, for E&Ps. You know, 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, you know, 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, run remotely from Houston.
And so there's a 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, they've shown where they can improve the uptime of engines, transmissions, you know, fluid ends, things like that, just by watching, you know, the thousands of 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%-80% of every bit that goes in every well across the United States and Canada. This is a huge amount of information.
Now, we're not getting into the E&P's remit of subsurface reservoir, you know, what does the geophysical structure of a basin look like? But, you know, when you look at operational data, you know, from drill bit to drilling rig, through directional drilling, through, you know, wireline, setting plugs, perforating, hydraulic fracturing, all those operational pieces, we'll have the broadest set of operational data of any oilfield services company across the U.S. What that does, that allows us to look at how we're 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. Let's talk about that. Obviously, the page one there was the activity outlook.
We always wait for your conference.
We always do. I love it. You took. You know, you preempted some of my questions here, but that's okay. So you did four. I think you quoted 48 rigs starting to reactivate, I believe, in October for fourth quarter, rigs starting in October and additionally, in 2024. So maybe just walk us through that. You know, what gets you to four? What gets you to eight? Is it customer type? Is it basin type? Just maybe a broader view on this, the activity you put out.
Yeah. When we did the last earnings call, we said: Hey, look, you know, the macro is strong going forward. There's some high-level discussions happening. And then, you know, this week, we were able to file the presentation and say: Look, we've signed contracts for four drilling rigs that are starting in the fourth quarter. We're in discussions on another four 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, you know, the macro driving this on where commodity prices are. And the four that we signed contracts for and the other four we're in discussions on, those are a mixture of oil, a mixture of gas, a mixture of publics, a mixture of privates.
Everybody's wanting to jump back in, just looking at where commodities are. You know, oil, WTI is plus or minus $80. It's got some relative stability again. And then natural gas. You know, natural gas was the driver for all the softening that we really saw in 2023. And if you look at the forward strip, you're already above $3.50 in December and, you know, plus that going into 2024. And a number of our customers that work in that Haynesville area or feeding into the Henry Hub from South Texas or from Oklahoma, you know, they need $2.75 or greater. Well, here we are in December at $3.50 and moving higher in 2024. So the macro is driving this on commodity prices. And then we haven't even talked about LNG.
I think when you look at natural gas and the increasing activity in natural gas, think about it in terms of two 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 2024 will be another event to start to build well inventory and natural gas as well.
So the four 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 two years? What? Has the term changed at all?
So there's a mix of 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 the low 30s, but that's still a pretty good number. You know, 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, there was going to be a big price collapse, and it just really didn't happen. You know, so our pricing's 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. Do you feel comfortable with that 116 mark in the bottom as you've added these 4 - at least these 4 rigs?
You know, there might be some day-to-day moving in there, but, I mean, hey, we got 4 rigs that are going out for sure in the fourth quarter. So yeah, we're somewhere around the bottom right now.
And then last question on the rig count. Industry rig count, what do you think we can get up to 700—with the 700 by the end of next year? Or do you think we'll stay in this range around 650?
Yeah, I'm putting a stake in the ground. Baker Hughes rig count, we're going to be over 700, you know, by the end of 2024, 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 2025.
All right. I like it. Let's move over to completions. 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 from Liberty, talking about maybe some and in ProPetro, talking about some activity stopping up through the fourth quarter, that one 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?
Yeah, a few different things. So on legacy Patterson-UTI, with our Universal division that's merging into NexTier. You know, we had dropped to 11, but we knew we were going back to 12 in the fourth quarter. We were actually carrying the people for that 12th crew, you know, 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, you know, with the combined entities NexTier, Universal all merged together as NexTier Well Completions.
I think you're going to see that activity picking up, you know, around the end of the fourth quarter. The other piece of that is, you know, we get a lot of questions about what do we think seasonality is going to do this year? You know, 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. Obviously, that's 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 create a dedicated market. Really didn't happen. Legacy Patterson is a bit more spot. NexTier's 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 3-4 years in this completion space, you know, you've seen more discipline and more supportive on the pricing side. So again, you know, there's this fear of price collapse with the softening in the market this year, and it just really didn't happen. And, you look at what NexTier's done, they've done a great job. Their dedicated percentage is maybe around 70%-80%, and so that pricing really didn't move for them. Their activity held up really well, and, you know, as we combine the Universal spreads into that, you know, it's going to stay roughly about the same in terms of percentage. And so, you know, we just, you know, I'm very positive on where this market is. It's just become very constructive.
You know, with the, with Ulterra 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, you know, before the E&Ps really get into some of the season of negotiating with us, is positive for us and positive for the market to have these two companies already put together. So, you know, I just think that market's just become a lot more constructive than it has historically.
Do 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 the question of, of recapitalization of, 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. Do you think that will drive going from spot to the dedicated model?
Well, our legacy frack fleets were really about the same percentage of, you know, primarily natural gas with the dual fuel as NexTier. So they were in good shape from that standpoint. You know, when we did see the slowdown, this year from the natural gas, and that put pressure on all the markets around Texas, then we ended up with a little more, 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, you know, the combined entity to have, you know, dedicated fleets at around that 70%-80%. But, you know, 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, from that standpoint.
So just to follow on, on the completions. I mean, I know you talked about legacy going from 11-12. Where is next year at, as far as their fleet count?
You know, 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 at a total of 3.3 million horsepower. And one of the challenges is, you know, we might be doing one frack spread with 22 pumps over here and then a simulfrac with 40 pumps over here. So what does a spread mean today? It really is hard to define. And so just coming out and saying, "Hey, we're working X number of spreads," you know, they could 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, I mean, I had to try. So North America efficiency is driving a structural change is a big theme that we're starting to hear, particularly from the E&Ps, who just continue to keep breaking efficiency records, expanding laterals, drilling faster, improving cycle times, increasing completions efficiencies. You know, 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, is there something that we're missing, that the services side will benefit in this trend as well?
Yeah. One of the things you have to bear in mind is, when you're looking at these macro trends, you know, what's really driving the data? And so when you're looking at the U.S. completions in terms of, you know, how productivity and efficiency is improving, you also have to remember the activity has gone through this bit of a softening. You know, where you've had, you know, overall, rig count and activity slow down and pumping of, you know, over 15%. And so what you're left with is actually the best wells with the highest productivity, the 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, you know, 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, that sector over the last few years, we've pushed the number of hours per day that we pump up significantly. You know, four years ago, it might have been 14-16 hours was a really good day on hydraulic fracturing. Now we're at, you know, 22 hours a day. It's unlikely that we're gonna go to 25 hours a day on pressure pumping. So at some point, you know, you're gonna hit the wall on that. And so I don't think you're gonna get much more efficient than what we do today. You know, small steps, yes, but the industry's made great strides over the last four years now.
So is it fair to say that it's, it's maximizing revenue per lateral foot, basically, from a services perspective, where it's, it's more stages, it's, it's more sand down hole. It's extending laterals where you get maybe paid on, you know, the length of the well, rather than just the day. Like, is there just different ways that you can approach it?
Yeah, and think of it in terms of service intensity, too. I think as, you know, people talk about tier one and tier two for the E&Ps and where their properties and their plays are, and as we get into more tier two, it becomes more service-intensive on our side, which is actually a benefit for us at this commodity price.
So, you know, 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 gonna be the deflationary tailwind for the E&Ps. That's OCTG, the steel, equal proppant, drill pipe. So maybe if you could break it down into those buckets, or at least we talked about the price of that activity, and maybe that consumable piece where E&Ps play.
Yeah, I think the E&P has got a big break this year, especially on, you know. 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, on drill pipe as well. And so they got a big break on that. Sand, you know, 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, you know, when you look at drilling and, and fracking and completing wells.
You know, I think if the mills stay caught up, they still have that break going forward into 2024 on steel, although activity, you know, is gonna increase. I still think the E&Ps will be in good shape from a budgetary standpoint. What you really didn't see in 2023 was deflation on the service side. You know, 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, you know, a frac spread. And so, I think all in all, it's still positive for the E&P budgets. It's still positive for our activity levels.
Is it a fair assumption to think that E&Ps could show CapEx budget that's, I don't know, ±10% down, yet on the services side, we could see increased profitability just because of those different buckets?
I think you could, and like I said, sand and steel are some of their biggest costs. You know, our service pricing really hasn't moved very much, and I expect, you know, rig rates and service pricing to kind of inch up next year as 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 expenses, I know you guys mentioned it in your deck as well, and you just touched on that you didn't see much deflation on your side from services. 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?
You know, when we were activating rigs back in 2020 and 2021, we were spending, you know, at least $2 million just on the activation in some cases, and these were built into the term contracts we were 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, you know, it's pretty easy to restart them. We were working 132 rigs back in January. We slowed down to 116. We're up to 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, you know, $100,000-$200,000 per rig, mostly OpEx and, you know, built into day rates. So, you know, 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 on 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 know, you have to remember that in our industry, we still have turnover. You know, 80% of the people that work at Patterson-UTI work somewhere in the field, you know, on a hydraulic fracturing spread, on a cementing truck, wireline crew, drilling rig, directional drilling operation. You know, it's still cold in North Dakota in the winter. It's still hot in Texas in the summer, and we still have turnover. 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, you know, it's not a downturn. We've only slowed down, you know, 10%-15% of 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 take care of itself as we work through this. And then as we start to ramp up next year, then 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 allocations and cash was a big theme, obviously. I mean, I know both Patterson and NexTier had 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, 8%-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 gonna stick with the 50%, you know, 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 announced today, whatever metric you want to throw out there. With 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, the mergers that we've been doing. But that's gonna come off here soon, and so, you know, we'll look at the market. We'll look at the dividend when the new board convenes and decide what to do with that.
I would say, based on where our stock trades, based on expectations and potential for the company, right now it looks to make more sense to do more buybacks than do anything with the dividend, and just keep the dividend where it is. We still have a lot of potential. You know, these businesses combined have the potential to produce a lot of free cash flow. We're gonna give 50% back to the shareholders. That also gives us some cash as well to start to buy back even more debt. Our team's done a good job of picking up some debt coupons at a discount over the last year or so, and so we'll look at continuing to do that and continue to deleverage at the same time as giving cash back to the equity holders.
No, that's, that's great. So we have a minute and a half left, and I don't want to leave out the international outlook as well. I mean, I, I know you guys are in-- 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 up the U.S. market and obviously feed into that system. So any final thoughts for us around the international outlook, both in the Middle East and maybe touch on Colombia as well?
Yeah, so Ulterra, 25% of their business is outside of the United States, outside of North America, in fact. So they have a good presence over in the Middle East. They're currently building a manufacturing facility in Saudi Arabia that will improve what's called their in-country value, which allows them to sell more product in Saudi Arabia. It will also help them support countries in the region. They've been growing that international business, you know, fairly well over the last five 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 rebuilt facilities in Colombia and Argentina as well. In terms of putting a drilling rig in the Middle East, there's always that potential. You know, we've looked at it for the last 10 years. You know, what makes sense for Patterson-UTI? We're certainly not gonna go there with just one rig. We're only gonna go there if it makes sense for shareholders. We can make money doing it. Otherwise, you know, we'll just do what we're doing and continue to produce a lot of free cash flow where we are.
Great. All right, Andy, that's all the time we have. Andy Hendricks, CEO of Patterson. Thanks for joining us.
Thanks for having me. Appreciate it.