Good day, and welcome to the ProPetro Holdings Corp. Fourth Quarter and Full Year 2025 Conference Call. Please note that this event is being recorded. I would now like to turn the call over to Matt Augustine, ProPetro's Vice President of Finance and Investor Relations. Please go ahead.

Thank you, and good morning. We appreciate your participation in today's call. With me are Chief Executive Officer, Sam Sledge; Chief Financial Officer, Caleb Weatherl; President and Chief Operating Officer, Adam Munoz; and President of PROPWR, Travis Simmering. This morning, we released our earnings results for the fourth quarter of 2025. Please note that any comments we make on today's call regarding projections or our expectations for future events are forward-looking statements covered by the Private Securities Litigation Reform Act. Forward-looking statements are subject to several risks and uncertainties, many of which are beyond our control. These risks and uncertainties can cause actual results to differ materially from our current expectations. We advise listeners to review our earnings release and risk factors discussed in our filings with the SEC. Also during today's call, we will reference certain non-GAAP financial measures. Reconciliations of these non-GAAP measures to the most directly comparable GAAP measures are included in our earnings release. Finally, after our prepared remarks, we will hold a question-and-answer session. With that, I would like to turn the call over to Sam.

Thanks, Matt. Good morning, everyone, and thanks for joining us today. 2025 was a year that was defined by uncertainty across the broader energy markets. There was a significant slowdown in completions activity as illustrated by our estimates that the Permian is operating with approximately 70 full-time frac fleets, down meaningfully from 90 to 100 fleets just a year ago. This headwind was compounded by tariff impacts and OPEC+ production increases that added pressure to commodity prices throughout the year, affecting budgets and creating a more cautious operator mindset. Despite these dynamics, ProPetro continued to deliver both operationally and financially and generated strong free cash flow, particularly in the fourth quarter. Our legacy completions business continues to generate sustainable free cash flow even in this tough market environment, which gives us confidence as this business helps fuel investments we are making in PROPWR, our future growth engine. Our solid fourth quarter performance underscores the industrialized nature of our completions business and the benefits of the technology and next-generation equipment investments we have made over the last several years. While we expect market challenges to persist into 2026, we continue to control what we can and move quickly by streamlining costs across the business, performing a granular analysis and taking decisive action. I'm proud of our team's ability to adapt quickly, rationalize costs and protect our asset base, thereby supporting our margins and competitiveness in the market. This will remain a key focus in 2026. ProPetro is a fundamentally strong company. We have low debt, first-class customers operating in the Permian Basin, a refreshed next-generation fleet and a team that continues to execute at a very high level. Even if challenging market conditions persist, our company's unique attributes position us to continue performing. As we've said before, market cycles create opportunities.…

Thanks, Sam, and good morning, everyone. As Sam mentioned, ProPetro's performance in the fourth quarter and throughout 2025 showcased the results of our strategy at work. Through disciplined cost control efforts and continued industrialization of our operations, we delivered resilient margins, strong free cash flow from our completions business despite a challenging market environment. We also advanced PROPWR meaningfully through new contracts, strategic equipment orders and flexible financing arrangement, positioning it as a growing contributor to future earnings. During the fourth quarter, ProPetro generated total revenue of $290 million, a decrease of 1% as compared to the third quarter. Net income totaled $1 million or $0.01 income per diluted share compared to net loss of $2 million or $0.02 loss per diluted share for the third quarter of 2025. Adjusted EBITDA totaled $51 million, was 18% of revenue and increased 45% compared to the third quarter. This includes the lease expense related to our electric fleet of $17 million. Net cash provided by operating activities and net cash used in investing activities, as shown on the statement of cash flows were $81 million and $39 million, respectively. Free cash flow for our completions business was $98 million, supported by strong EBITDA performance and reduced completion CapEx. Additionally, free cash flow was further bolstered by working capital tailwinds, which contributed an additional $28 million in cash. Moreover, we also generated $14 million from select asset sales and received $11 million from the note receivable related to the sale of our Vernal, Utah cementing operation completed in the fourth quarter of 2024. As Sam mentioned, our legacy completions business continues to generate sustainable free cash flow, demonstrating what we have consistently communicated over the past several years. Even in today's challenging market environment, our performance has remained steady and reliable. During the…

Thanks, Caleb. As we wrap up today's call, I want to address the significant interest we've received from various stakeholders regarding what differentiates PROPWR in the power market. how the business has positively progressed since its launch in late 2024 and how we foresee its evolution in the future. Some of this will be restating what you've already heard from me earlier in the call. Since launching the business, PROPWR has demonstrated a unique execution strategy. A key differentiator in our strategy is our belief that there is meaningful value in acting now, deploying assets into the market, capturing market share and then extending and expanding with both existing partners and those in our pipeline. Rather than waiting for the perfect contract, our speed-to-market advantage and confidence in operational execution enable us to build momentum and secure meaningful contracts over the past year. Market dynamics have also evolved and continue to evolve in our favor. Demand for power has accelerated in the Permian across the U.S. and global. Since PROPWR's launch, there's been a further awakening to the scarcity of reliable power and the data center and AI boom only amplify this issue. This has led to increasing demand for PROPWR within this arena. Our first data center contract announced last October was a pivotal moment. They signal our ability to participate in this arena and outside the Permian Basin, where we expect to grow in both deployed megawatts and contract duration over time. In the oilfield sector, we recognized early the emerging bottlenecks around power availability. Our foundation in the Permian positions us uniquely to solve these challenges for E&P customers, many of whom already know and trust ProPetro based on the proven performance of our legacy business line. We believe that no competitor matches our support infrastructure, logistics…

[Operator Instructions] Your first question comes from the line of Derek Podhaizer of Piper Sandler.

Maybe we'll start with expanding on some of your last comments there, Sam, on PROPWR. Just trying to think about the contracting cadence for 2026. You mentioned you have -- sorry, 240 megawatts committed today. I believe your average term is around 5 years. I know you're primarily addressing oil and gas, but obviously, we have the 60-megawatt data center contract. How should we really think about this mix and term evolving as we work through 2026? And then do you believe we'll be close to additional data center contracts this year?

Yes. Great question. I think for us, it's definitely -- and we've shown this, it's definitely a portfolio approach. I think as we're starting and launching the business from both a commercial and operational standpoint, we value being able to get equipment on the ground, generate returns and prove out our execution. You also heard in our remarks that we think of a larger share of our work over time is non-oil and gas. Those projects are many times larger and a little bit different from a time horizon standpoint in a very positive way. So we do think our mix will evolve in that direction a little bit more over time. And look, I think we're pretty proud to have contracted well over 200 megawatts in our first year standing up the company. And if we stick to our 5-year plan, which we think is very doable and executable, I think you can look for that level of contracted equipment from us on almost an annual basis moving forward to get to the 1 gigawatt number 5 years out. So we're really confident in our ability to continue to march down that path. That said, to the upside of that, some of these non-oil and gas data center, industrial type projects can be much bigger and chunkier in nature. So one of those can potentially change that time line and that mix very significantly if we're able to capitalize on one of those opportunities soon.

Got it. That's helpful. I appreciate the color. Switching over to the completion side of things. And I found it interesting, you mentioned 70 fleets today, down from 90 to 100. And I know one of the big themes as we work towards the end of the year is around frac attrition. You obviously have your version of frac attrition where you'll be refurbing some of your Tier IV DGBs. You talked about investing in direct drive to help offset some of your legacy Tier 2 diesel assets. My guess is that you'll be replacing those Tier 2 diesel assets, and I think this is a theme that we're seeing across the market. So maybe just simplistically, does the industry have enough frac equipment to get back to that 90 to 100 level if there is a call on demand? Maybe just some of your thoughts around the potential tightness we could see in this frac market if we do see some activity start coming back as we work towards the end of the year.

I think the short answer on can we get back to that 90 to 100 in the Permian, that's -- I think that would be a major stretch for the existing pressure pumping market. We have been banging the attrition drum loudly the last few years, and a lot of that is because of the information that we get through our own company and our own business and how difficult it is to keep a sizable fleet operating in these market conditions. That said, all along, when we've been talking about attrition, especially at the bottom end of the market, the smaller, less sophisticated players the market has been shrinking as well. So you haven't had circumstances in a way where that attrition necessarily shows through. That's why we continue to remind people that if and when activity picks up, it's not going to take very much to structurally tighten the market. That said, it's hard for us to see past what everyone else can see is the potential, crude oil supply glut and what weakness might remain there for kind of the near term. But we all know this business cycles that the supply and demand balance usually fixes itself. If and when that happens, I think we're going to have a frac operation that is very, very well positioned to capitalize on a much tighter market. We've got a great portfolio of technology starting to dribble in a little bit of direct drive gas equipment. We have one of the premier electric frac operations in the Permian Basin, and we have some very flexible diesel and dual fuel assets that are quite valuable in today's market as well. So we think that we're very, very well positioned to capitalize on that structural tightness when it does come, and we think it will.

Your next question comes from the line of Arun Jayaram of JPMorgan.

I wanted to just talk to you or ask you about, pardon me, just about kind of the mix between finance CapEx versus cash CapEx. In 2025, gentlemen, you financed just under 30% of your $281 million of CapEx incurred. And so is that -- how should we think about that mix relative to the 2026 CapEx program, which is kind of just above $400 million at the midpoint?

Yes. So in terms of funding our CapEx program, we have a lot of different options. We obviously did the equity issuance opportunistically from a position of strength, and we're always going to prioritize our use of sources of capital to fund our growth from a cost flexibility and size standpoint. So first of all, we like to use cash on the balance sheet, including organically generated cash from our business to fund growth. But like you mentioned, we have several flexible and competitive debt facilities in our ABL and cap finance facility. And we are also happy to have the Stonebriar lease financing facility in place, which is committed capital that we can draw on as needed. So I think that we have like several different attractive options, and we'll plan to use a mix of those.

Great. And just as my follow-up, you guys have 7 Tier IV DGB fleet, if my notes are correctly. Sam, could you talk about some of the planned upgrades between automation and the investments in the direct drive? Just trying to understand how your DGB fleet will evolve over time.

Yes. We made our first DGB investments probably a little over 5 years ago and built on that pretty aggressively for a couple of years and have held it relatively flat since peaking out around that 7 fleet range. We obviously have -- we're bringing in some of the direct drive units like we already talked about. We also have our electric offering and our diesel offering. And as I said, that portfolio, we find to be very valuable in the Permian Basin, where there is both stranded gas where we can capitalize on that type of situation with the customer, but also in other places where customers are selling their gas at a very reasonable price and might want to burn diesel or a blend the two. So it's probably hard to see from an external standpoint, but there's a lot of regional pockets in the Permian in size and sophistication of E&Ps that value all of these different types of offerings. And I think what we have now is a very good portfolio for us to be able to service the biggest, most sophisticated E&Ps in the Permian, but also the growing independence that still exist in an entrepreneurial area like West Texas and New Mexico. So I think in the near term, Arun, from like a portfolio mix standpoint, it's probably just more of the same for us. We talked about rebuilding some Tier 4s and maintaining kind of that 7 fleet type of capacity for that, but also making a nod to some of the newer technologies like direct drive that certain customers are very interested in. And on the -- you mentioned the fleet automation technology. Look, that's just really, in some ways, we believe the cost of doing business and the cost of playing the game at the most -- at the highest level in the pressure pumping sector where you've got to be able to bring those types of high-tech solutions to your customers and allow them to fine-tune their completions programs as much as possible, while at the same time, deploying technology internally into our business that allows us to extend equipment life and use more predictive maintenance tools, lots of things like that. So that's where some of these technology upgrades are coming from us. And I think to sum all that up, these are the types of things you have to do to remain competitive at the highest level in the pressure pumping sector. There's a lot of players that aren't making these moves in these investments back to kind of the structural tightness that we believe will exist in the future because the bar just continues to go higher every day from a performance technology equipment standpoint. And we like our position being able to compete in that game in the future.

Your next question comes from the line of Stephen Gengaro of Stifel.

I had 2 questions, Sam. The first one was just around the demand for power in the oil patch versus the assets getting pulled into other applications for data centers, et cetera. And is there any concern about the cost of power for the e-fracs and how that evolves and how that affects the frac business?

Yes. I'll answer the e-frac question first and maybe let Travis chime in on your first question. I don't think we have any concern around e-frac power right now. We kind of look at that market, and it having matured a bit over the last year or so. That was a very aggressively growing market for a few years there when we were deploying into it and getting power to pair with that electric -- our FORCE electric frac equipment was a bit of a task at the time. But we think a lot of that equipment that's serving the e-frac market is in a pretty stable place given that, that market is not really growing that fast right now. And a lot of that power is more custom tuned and built for that very application. So it has a little bit of a more difficult time going other places in the power market. Travis, I don't know if you want to take his first question.

Yes. I guess the first question was just on the oil and gas demand relative to the data center markets. Clearly, we see both growing. The data center demand is much higher. We're excited to be able to diversify into both sectors. Really excited that we were able to kind of act quickly and execute in the oilfield here in our backyard and just get confidence and grow our fleet, but also the ability to do that has allowed us to participate in these larger and longer chunkier deals in the data center market. So we're just -- we're happy to be able to participate in both and have the equipment that I think serves both because of the high efficiency, low emissions that we've done.

And then the follow-up I had was just around when you think about contract duration versus terms on some of the data center contracts that you're looking at, should we think about the returns on the investment being potentially a little bit lower if you're able to secure long-term contracts. We've heard that from others, which when you have visibility of cash flows, it's a big positive, but the returns and our pricing could tend to be a little lower. Is that the right way to think about the blend?

Yes. I think it's a balancing act. I mean we're looking at a diverse group of contracts and duration and even site size. So we look at a number of different variables that we weigh into our return metrics, but there's a possibility as they go really long that we're willing to take something a little bit lower.

Stephen, I'll just add a little bit more to that and watching Travis and his team work through this commercial pipeline. There's always so much time and energy and assets that we can deploy. So I think everything that Travis said is highly accurate. It's definitely a balancing portfolio effort. That said, we prioritize real conversations with customers that are serious about making moves and cutting deals that are mutually beneficial to both them and what we have to offer in PROPWR. And I think what you've seen from us to date in the contracts that we've and the assets that we're going to deploy are to real projects that are going to generate real earnings and have real time lines. There's a lot of blue sky out there in this market that I think mostly materializes over time. But from a timing aspect, running a business like we run ours that's highly interested in real work and real earnings, we usually move to the front of the line, the people that are most serious about actually getting a deal done and getting equipment into the field.

Your next question comes from the line of Eddie Kim of Barclays.

Just wanted to ask about the cost of your power equipment and if it changes based on the end market. You mentioned you expect a larger share of your work over time will be towards non-oil and gas applications. To the extent more of your equipment goes toward data centers going forward. Just curious if the mousetrap or configuration is different such that the $1.1 million per megawatt cost estimate increases at all as a result? Any thoughts there would be great.

Yes. That's a good question. So the $1.1 million that we've talked about is for the modular equipment we bought today, definitely works at certain power nodes in both the oil and gas and data center market. As we evaluate technologies that might be a little bit larger and maybe more infrastructure-esque, I think there's a possibility that, that CapEx goes up a little bit on that equipment, but obviously requires a longer tenor on the contract and maybe larger contract size to justify that investment.

Got it. Got it. And then just sticking on the cost estimate. So you mentioned you expect the cost of the 550 megawatts ordered to date to be that $1.1 million per megawatt, including the [ Dallas ] plant. For the incremental 450 megawatts to get to your 1 gigawatt target by 2030, do you expect that incremental capacity to cost a bit more than your estimate. So just -- I mean, just curious, are the OEMs starting to raise pricing industry-wide? How is the pricing environment for power gen equipment changed, if at all, over the past 6 months or so?

Yes. We're evaluating the mix on the additional 450, have a lot of optionality there right now. I think the important thing is that the return metrics will be the same regardless of the CapEx input. So we're evaluating projects and different industries a little bit different from an equipment perspective, but looking at the same return profile across the board.

Your next question comes from the line of Jeff LeBlanc of TPH.

In the press release, you referenced that the opportunities to deploy incremental fleet is limited, but have you had success transitioning your existing customers from Tier 4 -- excuse me, the Tier 2 to the Tier IV DGB assets? Because I think at some point, you had some assets idle.

Yes, there's been a little bit of that. But I think going back to kind of some things that I mentioned earlier, it's more of a specific tool for a specific customer and region right now. Gas prices can vary greatly across the Permian Basin, depending on where you are and what your pipeline deal is. So it's a little bit less of we need to grow a customer from diesel to dual fuel into electric. That was a game that we played very heavily and very successfully into the last several years. But I think there's a little bit more stability in the market right now. And I think at the given activity levels, crude prices, gas prices, I think most of the E&Ps that we're dealing with, they know exactly what they want, and they know exactly what fuel sources that they want to utilize wherever their specific acreage might be. So there's still a little bit of that going on, but I'd say that's a little bit less of a game that's being played today than it was maybe a couple of years ago.

Your next question comes from the line of John Daniel of Daniel Energy Partners.

Just a couple of quick housekeeping. Sam, can you say how many of the Tier 2 fleets are working today?

2 or 3.

2 or 3. Okay. And then on the direct drive, I got in a little bit late on the call. Did you specify like how many new units you're adding and just a little bit more on the strategy there?

Yes. We've had a couple of units running for the last 6 months or so. They're part of kind of like a pilot program for us. We're going to add more than that here with kind of the CapEx that we've outlined, but not a lot, John. These aren't like fleets at a time. This is kind of like gradually adding them in with some of the attrition that we're seeing in our own fleet and taking them to very specific customers that have showed an interest in that equipment and committing to it over some period of time. So it's not -- this is not like a major reinvestment cycle for us. This is kind of an evolution, kind of slow evolution that is being -- listening to certain customers of ours. I guess it's a little bit more of a rifle approach, so yes.

Fair enough. And then last one, just since I'm a traditional energy guy. Can you just give us some thoughts on wireline and cementing and what you're seeing in both of those service lines today?

Yes. Wireline Silvertip team has done a fantastic job over the last year managing the market volatility. I think we've probably been a net market share winner in that business, along with really good margins, really good pricing discipline. There's been maybe a little bit of a flight to quality in the wireline business, and we benefited from that. Very stable right now. We've got a good amount of overlap with our frac fleets, which also creates good integration and stability, good efficiency. Cementing, we've seen the rig count throughout last year continue to drill lower and it's still at a pretty depressed area. That's hit that business a little bit. But we think the bones are there to have a really great business over time. I think we're probably top 3 or 4 market share there, very competitive, one of the best labs in both plants in the Permian Basin and a great footprint on the Western side of the basin in the Delaware with the Par Five acquisition that we made a couple of years ago. So that business is down a little bit relatively to something like powerline -- wireline and frac, but still in a really good strong position.

[Operator Instructions] Your next question comes from the line of Scott Gruber of Citigroup.

I want to come back to the power side. Demand for on-site generation for data centers appears to be taking another step higher here, seeing CapEx numbers from the hyperscalers continue to grow. And you mentioned that it's unlikely that the data center market pulls e-frac megawatts due to the design configuration differences. But is the pull from the data center market starting to improve the terms and conditions and potentially the return profile that you're able to achieve on incremental investment in megawatts into the oilfield microgrids?

Yes, I think it helps. The competition certainly raises all boats, I would say. So the limited amount of megawatts is being certainly recognized by the oilfield players as well, and they see the demand constraint or the supply constraints, both from the utility and from a behind-the-meter perspective. So we see that all as positive for what we're looking at.

With no further questions, that concludes our Q&A session. I will now turn the call back over to Sam Sledge, Chief Executive Officer, for closing remarks.

Thanks, everybody, for joining us today. Thanks for your interest in ProPetro. We look forward to talking to you again soon.

That concludes today's conference call. You may now disconnect.