LBRT - NYSE

Welcome to the Liberty Energy Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Anjali Voria, Vice President of Investor Relations. Please go ahead.

Thank you, Wyatt. Good morning, and welcome to the Liberty Energy Second Quarter 2025 Earnings Call. Joining us on the call are Ron Gusek, Chief Executive Officer; and Michael Stock, Chief Financial Officer. Before we begin, I would like to remind all participants that some of our comments today may include forward-looking statements reflecting the company's view about future prospects, revenues, expenses or profits. These matters involve risks and uncertainties that could cause actual results to differ materially from our forward-looking statements. These statements reflect the company's beliefs based on current conditions that are subject to certain risks and uncertainties that are detailed in our earnings release and other public filings. Our comments today also include non-GAAP financial and operational measures. These non-GAAP measures, including EBITDA, adjusted EBITDA, adjusted net income, adjusted net income per diluted share, adjusted pretax return on capital employed and cash return on invested capital are not a substitute for GAAP measures and may not be comparable to similar measures of other companies. A reconciliation of net income to EBITDA and adjusted EBITDA, net income to adjusted net income and adjusted net income per diluted share and a calculation of adjusted pretax return on capital employed and cash return on invested capital as discussed on this call, are available on our Investor Relations website. I will now turn the call over to Ron.

Good morning, everyone, and thank you for joining us to discuss our second quarter 2025 operational and financial results. Liberty delivered an exceptional second quarter amidst increased macroeconomic uncertainty and energy sector volatility. Revenue and adjusted EBITDA increased 7% and 8% sequentially, respectively, against an industry backdrop of softening completions activity. This strong performance is a direct reflection of the outstanding contributions of our team, safely driving record efficiencies and increased utilization that more than offset industry pricing headwinds. Our outstanding performance with lasting customer loyalty and reinforces our position as the fleet of choice in a competitive market. Tariff policies, the accelerated unwind of OPEC plus production and geopolitical tension drove renewed uncertainty in the energy sector. During the quarter, we collaborated as partners with our customers to drive greater efficiencies, which is likely to grow our market share as activity pulls back in the second half of 2025. Amidst market pressures and near-term reductions in customer activity, we are planning to modestly reduce our deployed fleet count and reposition this horsepower to support expanded demand from long-term partners for our simul-frac offering. We are leveraging our full suite of completion products and services, including frac, wireline, sand, chemicals, logistics, fueling services and top-tier engineering and diagnostic tools to drive increased engagement with our customers. We have created a unique competitive position that allows us to stay agile in dynamic markets. We are excited to bolster our technology leadership with rapid progress on our cutting-edge digiPrime enhancement with the industry's first variable speed natural gas reciprocating engine. This is truly the next wave of technology in frac fleet design. We now have 2 variable speed digiPrime units pumping in the field that have together completed over 1,700 hours of testing in the high- pressure environment of West Texas. These units provide precision rate control and increased torque, increasing both operational and capital efficiency. This latest technology advancement expands our ability to offer a 100% natural gas solution. Our successful development and field testing during the second quarter reflect our commitment to continued innovation in high-efficiency, low- emission technologies. Three years on from our first digiFleet deployment, the results continue to exceed expectations. The platform is delivering substantial, measurable benefits, most notably in the durability and performance of key components. One of the core advantages of operating on 100% natural gas is the reduced wear and tear on engine components compared to diesel. Natural gas combustion produces fewer particulates, extends oil life and significantly reduces engine stress, factors that contribute to engine lifespans expected to be 2 to 3x longer than conventional diesel and dual fuel-powered systems. We are already seeing this play out in the field. Digifleet power ends are lasting twice as long as conventional power ends while managing significantly higher load. Similarly, fluid ends are achieving twice the horsepower hours of their conventional counterparts. These early results are clear evidence of the operational and capital efficiency gains enabled by our digiFleet. They directly support our mission to deliver the lowest total cost of service to our customers while setting a new standard for sustainable performance in the field. We also completed a successful field trial of the industry's first last mile sand slurry system. The system performed as designed, consistently exceeding delivery volumes in conjunction with our proprietary water handling system. By transporting sand slurry via pipe, it is expected to reduce costs, improve delivery reliability and decrease dust, emissions and road maintenance for our customers. Growing demand from data centers and industrial users necessitates a collaborative approach to address power service requirements that increasingly surpass the traditional utility offering. During the second quarter, we announced 2 strategic alliances for the development of power facilities. In Pennsylvania, we are collaborating with Range Resources and Imperial Land Corporation to provide power services to anchor a strategically located industrial park tailored for scalable development with advantaged access to Marcellus natural gas. In Colorado, our strategic alliance with AltitudeX Aviation Group will support a proposed development at the Colorado Air and Space Port powered by a Liberty Microgrid. These partnerships address the barriers that commercial and industrial developers face, including access to suitable land, integrated power management solutions and reliable fuel supply. Together, we offer a turnkey solution that combines on-site generation, market integration and infrastructure readiness to meet the evolving needs of high-demand users. Our recently announced collaboration with Oklo represents an exciting path towards delivering integrated next-generation power solutions for sophisticated large load customers. This comprehensive approach combines the speed to market of Liberty's Forte distributed natural gas power and high-performance load management solution to meet immediate demand with a path to integrate grid power management and baseload small modular nuclear reactors with Oklo's Aurora powerhouses. This complete solution is designed for data centers, industrial sites and utility scale facilities, providing rapid deployment, enhanced grid optimization and long-term price stability. This ultimately enables a seamless path to reduce carbon intensity without sacrificing reliability and flexibility. Liberty was an early investor in Oklo, committing $10 million in 2023. After evaluating companies and technologies across the advanced nuclear space, we identified Oklo's innovative business model, small and scalable design and differentiated technology as an important strategic solution to meet the growing power demands of large-scale energy users. We are thrilled to be aligned at a pivotal moment where collaboration can drive meaningful impact. Together, we will deliver an unprecedented fully integrated power and grid management solution, offering large-scale energy users a new level of reliability, scalability and flexibility that simply hasn't existed before. While oil markets continue to evolve in response to dynamic global economic and geopolitical developments, North American production has remained relatively stable. As the world's largest supplier of oil and natural gas, U.S. producers continue to play a vital role in delivering reliable energy to global markets, supporting domestic industrial activity and power demand and providing strategic leverage in the geopolitical landscape. Recent events ranging from shifting tariff policies to rising regional hostilities and mixed economic signals affecting global oil demand have not yet driven a meaningful North American production response. Larger, well-capitalized producers with strong balance sheets and highly efficient operations enjoy healthy well economics, enabling them to weather commodity price volatility. Intra-quarter price fluctuations created hedging opportunities, further tempering supply side reactions. Producers are targeting a relatively flat production profile, sustaining a baseline of frac activity to offset the natural decline of producing wells. Completions activity is anticipated to gradually slow during the second half of the year, reflecting disciplined capital deployment and contributing to market pricing pressures on services. This slowdown in activity is expected to accelerate equipment cannibalization and attrition, which fundamentally improves the supply and demand dynamics within the services industry over the cycle. Today's larger producers require a technically superior offering to meet the rising demand for efficiencies and engineering support that few service companies are positioned to deliver. Liberty's unmatched portfolio breadth, integrated services and technical innovation uniquely enable us to deliver greater value to our customers and drive outperformance. As we look ahead, the strategic investments we have made in completions through cycles enhances our ability to support customers in an evolving landscape. We are leveraging our integrated suite of completion services, cutting-edge technologies, industry-leading partnerships and the dedication of our exceptional team to navigate market uncertainties. Within our power business, LPI delivers a robustly engineered end-to-end energy solution, uniquely integrating on-site generation and load management, ISO market participation and advantaged retail supply, creating a comprehensive flexible approach that redefines reliability and cost efficiency in deregulated regions. We are excited by LPI's future growth and its ability to contribute to our track record of delivering superior long-term returns while balancing disciplined investment with a strong balance sheet through cycles. I will now turn the call over to Michael to discuss our financial results and outlook.

Good morning, everyone. I'm pleased to share that we achieved solid financial results despite the ever-changing macro landscape of the second quarter. Liberty's activity levels climbed quarter-over-quarter despite industry-wide frac activity declines observed during the period. We saw a resulting increase in our market share, a trend we expect to continue in the back half of the year given our differential service offering and expected relative outperformance. We also made significant progress in our power business, cultivating long-term relationships that will drive future successes. In the second quarter, revenue of 2025 -- revenue was $1 billion compared to $977 million in the prior quarter. Our results increased 7% sequentially as higher activity in nearly all our business lines more than offset pricing headwinds and softer conditions in the Permian sand market. Second quarter net income of $71 million compared to $20 million in the prior quarter. Adjusted net income of $20 million compared to $7 million in the prior quarter and excludes $51 million of tax-effected gains on investments. Fully diluted net income per share was $0.43 compared to $0.12 in the prior quarter. Adjusted net income per diluted share was $0.12 compared to $0.04 in the prior quarter. Second quarter adjusted EBITDA was $181 million compared to $168 million in the prior quarter, an 8% sequential increase. General and administrative expenses totaled $58 million in the second quarter compared to $66 million in the prior quarter, which included a noncash stock-based compensation of $6 million. G&A decreased $7 million from the prior quarter, primarily due to accelerated modified stock-based compensation associated with Chris' departure in the first quarter. Other income items totaled $58 million for the quarter, inclusive of $68 million on gains and investments, offset by interest expense of approximately $10 million. Second quarter tax expense was $24 million, approximately 25% of pretax income. Cash taxes were $20 million. In the second half of 2025, we now expect tax expense rate to be approximately 25% of pretax income and approximately no payment on cash taxes in the second half of the year. We ended the quarter with a cash balance of $20 million and a net debt of $140 million. Net debt decreased by $46 million from the prior quarter. Second quarter uses of cash included capital expenditures and $13 million of cash dividends. Amidst market uncertainties, we elected to refrain from share buybacks to allow a period of assessment while focusing on the execution of our long-term strategic plans. We will continuously monitor evolving macroeconomic conditions and remain flexible and value-focused in our buyback approach. Total liquidity at the end of the quarter, including availability under the credit facility was $276 million. Subsequently, in July 2025, Liberty expanded its credit facility in support of strategic growth in power generation with a $225 million increase in our aggregate commitments to $750 million, subject to borrowing base limitations. Net capital expenditures were $134 million in the second quarter, which included investments in digiFleet, capitalized maintenance spending, LPI infrastructure and other products. We had approximately $3 million of proceeds from asset sales in the quarter and $51 million of proceeds from the sale of equity securities. We now expect total capital expenditures for 2025 of approximately $575 million, approximately $75 million less than planned, roughly evenly distributed between reduced completions CapEx and delays in delivery of power generation relative to expectations in January. As we approach 2026, we will assess market volatility and implications for completions CapEx while continuing to lean into the growth potential of our Power business. After a strong uptick in the second quarter, we expect third quarter revenue and EBITDA to soften sequentially. Many service providers that had already experienced white space during the second quarter were quick to respond unconstructively, resulting in pricing headwinds. As a result, the macroeconomic developments over the last 3 months, we are withdrawing our full year EBITDA target range provided in January, and we'll provide additional color on our fourth quarter expectations on our next earnings update. In spite of the anticipated frac market softness, we are encouraged by the opportunities ahead and our ability to create value. We are confident in our ability to demonstrate continued outperformance. We are working diligently alongside our customers to provide best-in-class service and engineered solutions that respond to evolving well economics and drive more entrenched relationships with these customers. Our power opportunities continue to expand, and we're excited by the relationships we are building that will position us to deliver comprehensive integrated long-term solutions. We are deeply committed to generating superior returns for our shareholders over the cycles. I will now turn the call back to the operator for Q&A, after which Ron will have some closing comments.

[Operator Instructions] Our first question will come from Stephen Gengaro with Stifel.

So 2 for me that are probably connected, and we get asked this a lot, so I'll ask you. When we think about the power generation side of the business, can you talk about, one, sort of what the current sort of supply chain looks like for incremental capacity? And then the other question is sort of around kind of the potential for some of these assets to be contracted over the next couple of quarters?

Yes, Stephen, so let me tackle the first one. On a -- from a supply chain standpoint, there definitely is, particularly on the gas recip side, incremental capacity available beyond, for example, what we have already procured. We have had conversations with our supply base. And certainly, I think this is specific to Liberty and our relationships there have identified availability of meaningful additional capacity. We could significantly expand our order book for 2026 if we so desire to and have that -- have those assets delivered over the latter part of '26 and headed into early 2027. So we have that opportunity there. I think realistically, if we wanted to, we could probably more than double our order book for 2026 if we chose to. With respect to the second part of your question, maybe I'll tackle it and then if Michael has anything to tack on from his standpoint, he certainly can. We've announced a number of larger partnerships. And of course, those are bigger development efforts. And so as you think about things like permitting and whatnot, there's a timeline involved in that sort of stuff. And so those ones are going to be a little longer as we think about asset deployment for something like that. You're probably talking about into 2027 for those types of bigger partnerships. We are going to start deploying power generation assets this fall. So we have 3 sites, 1 in Colorado and 2 in Texas that we will begin to deploy assets on here in the back half of the year. And I'd expect we'll begin generation for that sometime in 2026.

Great. And then -- just as a follow-on, given the Oklo announcement, it sounds like -- I mean, one of the things that Wall Street is trying to figure out is kind of this sort of bridge to something down the road, whether it's grid power or SMRs or whatever it might be. But your relationship with Oklo, it seems like it's at least partially centered around creating this kind of long-term power solution until some of these SMRs are more active, which is probably 5 to 7-plus years. How do we think about that? Is that a long-term relationship as baseload? Or could some of what you're doing be kind of included as backup power as some SMRs come on longer term?

I think you're generally thinking about that in the right direction. But I'd say even broader than that, Stephen. Of course, we have this timeline delta. We have customers who desire to bring their facility, industrial complex, whatever it might be online sooner than might be possible if they were going to wait for an SMR. And so in the first phase of this, we do provide that bridge for start-up and continuous operations until we can deploy an SMR to the site. Once we get an SMR there, though, you have to remember that nuclear is best suited to baseload power to long-term steady supply of a continuous amount of kilowatts or megawatts. If you think about a data center, you have there an asset that has highly variable load demand, loads that can fluctuate by a significant percentage of total load over fractions of a second. And so you need a mechanism for response to that. The partnership with natural gas recip and ultimately some more advanced technology, I think capacitance, super capacitance, it enables that variability and -- but as a partnership, not as one or the other. The other advantage is with gas on top of nuclear, you rely on the nuclear for that baseload capacity. But when and if the grid arrives, it also allows some flexibility in that regard. You could think about our ability with fast response gas to be able to keep an eye on prices available on the grid. To the extent there is abundant wind and solar that day and power prices are quite low, we could ramp down the gas and take advantage of that opportunistic pricing. To the extent the inverse is true, and we have very, very high grid prices, we have the ability to start up all of that gas capacity, make sure we're taking care of the core customer, but also putting some of that power out on the grid. So I think if you view this as a very long-term partnership, you can see that there are some real economic opportunities with nuclear paired together with gas, not just in the near term, but over decades to come.

Our next question will come from Scott Gruber with Citigroup.

I realize all the moving pieces on the completions business makes it tough. But just wanted to get some more color on the second half. Activity is down, but you're redeploying some capacity, you're taking share, but pricing is a headwind. So just can you provide some more color on the revenue trajectory and EBITDA trajectory in 3Q? And what's the early look for 4Q? Will the seasonality be worse than normal? Or are we in a situation where -- because customers are slowing today, that may moderate the 4Q decline? So just some color there would be great.

Yes. Good question, Scott. Certainly, we're coming off of an incredible high in Q2. We had a tremendous quarter this past quarter. But as you've noted, we've seen activity start to come down. That's predicated by rig count falling, and we've seen that happen over this quarter and continue into the start of the third quarter. We always, from a completion standpoint, lag that by 3 or 4 or 5 months. And so we're expecting to see that impact on the completions world over the back half of the quarter. And so while we had very strong utilization in Q2 relative to that, we are starting to see more white space appear on the calendar. I think it's our expectation that we're going to see an activity reduction maybe of order mid-single digits or thereabouts in terms of our utilization of the asset base. As we noted, we're repurposing assets a little bit. We are taking down our fleet count, but with the desire to get to increased efficiency, our customers are seeking more simul-frac work. And so we're repurposing that horsepower, lowering overall fleet count, maintaining effectively our horsepower utilization, though and running fewer larger fleets to meet that demand to drive efficiency in these environments. Now of course, with that additional white space as we look out in the back half of the year, we're going to see some pricing headwinds, as you noted. And certainly, we expect that to be a piece of the puzzle as well. At this point in time, I think we'd say probably low single digits pricing headwinds. And there's a little bit of context to that. Of course, we have relatively firm pricing with our leading edge technology, I think the digiFrac and digiPrime assets that are out there, a little more challenged pricing with the older assets, particularly the diesel equipment, but averaged across the asset base, probably something in the low single digits range. As for Q4, probably a little early to tell at this point in time. I certainly appreciate your thinking there, and I hope that's how it plays out. But I think for us, just given how bumpy the market has been, and we're probably going to take a bit of a wait and see on Q4. And as we get a bit closer to that, we'll be able to provide some -- probably a clear outlook there. Michael, anything to add?

No, I think you covered it well there. I think at least normal seasonality for Q4 coming off Q3, but we'll have some more clarity as we get closer.

I appreciate it. And then I wanted to come back to the Oklo alliance. It's certainly an interesting alliance. Now Oklo, I believe, has a bunch of MOUs for the reactors. So with the alliance, will you be targeting customers with MOUs? Are they clamoring for a kind of faster time to first power? Or will the alliance be mainly targeting new customers?

No. So when you think about it, the -- with the Oklo powerhouses, these are large, sort of very large customers, right? And so these are multiyear development MOUs they have. So when you think about it sort of how that customer wants to develop power over the next 5 to 10 years. So yes, so definitely, the Liberty, Oklo Alliance will be working on with those customer relationships. This allows the ability to bring power forward and having a more integrated and grid interconnected long-term solution, which sort of solves a lot of the problems when you think about you want to get to a long-term nuclear solution where people are still focused on a low-carbon solution. And -- but you want to be able to get to that point where we want to win the AI race now, right? So the bringing of Liberty's Forte generation and load management solution, which allows us to manage those incredible variable loads that are driven by the AI data centers that they want to be -- they want to deal with. Also the seasonal variability due to the significant parasitic load of cooling of data centers, right? So therefore, the Oklo powerhouses are great for the baseload portion of it and the Liberty Gas will be a 20-plus year generating asset as part of that integrated solution. So yes, so we will be working diligently to bring forward a lot of this data center development that has been talked about over the last year.

Our next question will come from Keith MacKey with RBC Capital Markets.

Just maybe first start out on the sand slurry pipe system you talked about in the release. Can you just give us a sense of the operational advantages or cost differential that, that type of sand transportation provides versus the traditional methods?

Yes. Good question, Keith. It's -- I won't get into the weeds on the numbers, but to give you some sense of how that difference might play out, I'll give you a very simplistic scenario. You can imagine an environment where there is an existing proximity mine, so effectively a wet sand mine located in the middle of somebody's contiguous acreage. The sand slurry system allows us today, we're using a number of around 10 miles to never put that sand in a truck to have that leave a proximity mine in a slurry pipe and be pumped all the way to location. Once we get to location, we remove the water from it, we stack it in a wet pile just like you would see with any other pile system and have that sand ready to go for use on location. So in that extreme case, we actually never put a truck on the road to handle sand. In maybe a slightly different example, probably one of the biggest challenges we have when you think about the logistics for sand is the last portion of the last mile of delivery. So if you think about West Texas, the Permian area, we might go and get sand from one of the mines in the Kermit, Monahans trend, we'll load that on a truck. We'll drive down a highway for a good portion of the way. But then ultimately, we end up on a ranch road. A ranch road that will have a speed limit of 10 miles an hour that is relatively well maintained, might have some cattle gates along the way. That's a significant use of time for a truck. It might be half of the driving time, even though it's only a fraction of the distance that they have to travel. There's also a significant cost to the E&P to maintain that road when we have to deliver hundreds of trucks of sand up and down that each and every day. You can appreciate that, that's the most volume from a vehicle standpoint going in and out of location for the operation of the frac. The slurry system allows us the opportunity to remove that entirely. We could have the sand trucks deliver only on pavement and thus maintain their round trip efficiency, maximizing the number of loads they get in the day and minimizing our per ton mile cost for that and then transfer that sand into a slurry system to deliver the rest of the way to location. We eliminate the truck traffic, the dust, the noise that comes with that. We give the truckers a more efficient time frame, and we basically remove all the road maintenance costs that come with all of that traffic on the road. And so we view that as the economic opportunity for the customers in this. It's not going to be an application that works every place, but I think there are going to be a lot of opportunities in basins where it's going to make a lot of sense.

Got it. I appreciate that color. I appreciate the comments on the utilization softening and the pricing as well across the asset base. Can you just give us a sense of how the act of consolidating some of your horsepower into fewer fleets might change the earnings power of the business on a like-for-like basis. So would you expect that the simul-frac operations to have higher earnings power or lower earnings power relative to your prior asset footprint without any of these additional changes?

Yes. There's a small change there, Keith. But in relative terms, we -- services are priced on the basis of a return on the assets themselves, right? So whereas each -- we will have less fleets, each fleet will be slightly more profitable on a fleet basis. But on a per horsepower basis, you're going to see some similarities and you're going to see some reduced average cost per lateral foot for the client. So it's a bit of a win-win for everybody.

Our next question will come from Marc Bianchi with TD Cowen.

I wanted to ask a couple of clarifications around sort of the outlook for the second half here. Ron, you were talking about the drawdown in activity, maybe something on the order of mid-single digits and then add a few percentage points of price to that. So it would appear maybe we're talking about something like 7% or 8%. Is that what you expect for third quarter? Or is that kind of a mix of third quarter and fourth quarter? And then I don't know, Michael, if you want to try to help us with how to think about the operating leverage, the decrementals that we would see on that type of a revenue decline?

I sort of -- you broke up just a bit in the middle there on this end. Sorry, Marc. Can you just repeat the question?

Sure. It seems like between the activity and price that you talked about, it sounds like maybe it's something like a 7% or 8% decline. The question was, is that all in 3Q? Or is it sort of spread over the second half? And then how much of a decremental margin should we be looking at, recognizing there's some price and some mix and lots of moving pieces.

So yes, Michael is doing some quick math for you there, Marc. But I think -- I don't think I'd add those 2 things together necessarily to get to 7% or 8%. I think you want to think about those things independent of one another, and that will get you to probably some slightly different numbers than just the sum total of the 2. Michael, do you want to provide some color?

I think you're right. I mean I think if you look at those numbers and you get sort of mid-single-digit activity where you've got decrementals that are a little elevated to your usual sort of 35% because of as we are changing out our fleet count. And then you've got, as Ron said, some single-digit pricing decline on average across the whole fleet. I think you can get to the math on getting to the numbers with that, Marc.

Got it. And that's all happening in third quarter. Like this is essentially what you think for the calendar third quarter?

The general assumption is pricing stays relatively flat through sort of we're seeing those drops now as best we know, it stays relatively flat through the fourth quarter, and you'll see some seasonality. But again, we'll have a lot more clarity on that when we get to the next earnings release.

Yes. Okay. Makes sense. And then the other one I had was on the CapEx reduction, you mentioned some of it was frac and some of it was some sort of slower delivery for the power equipment. I guess, could you help us understand how much is each? And then with the power piece, was that your decision or the vendor's decision? And what's the chance of seeing further delays there?

It's about split 50-50. You've got to remember on the power side, really, that's just a firming up of delivery times. Remember, we gave you some numbers at the beginning of the year in January, right? So things sort of as far as those delivery times firming up between sort of November, December, January and February of next year. So that's just a firming up of the actual delivery times out of the factory. So not a big number, but you've got an artificial 12-month period we're talking about here. And then on the frac side, yes, about 50% of that reduction comes out of the frac side as we start to tamper down CapEx on the completion side of the business as we move towards where we see the market changing as we continue to drive strong free cash flow out of that business as we go forward.

Our next question will come from Saurabh Pant with Bank of America.

Ron, maybe I'll start with the big picture question. Like you said in your prepared remarks, right, it seems like E&Ps are solving for [flat production], right? So if we think about that, new frac, I think, close to 20% of the wells in North America. As you look forward and have your discussions with your customers, Mike, how do you think customers might budget for 2026, right? Just broad strokes, any high-level thoughts on that?

Yes. I'm certainly happy to provide my speculation on that. Of course, I would love to be in the boardroom with them when they're making those decisions. But my suspicion is that we are going to see the E&Ps onshore North America generally try to hold production at levels somewhere close to where they are today. It's my opinion that it would be difficult to regain that market share in the foreseeable future. And so my sense is barring some meaningful economic dislocation, we're going to see them with a budget that has sufficient activity to hold production close to where it is right now. We maybe see a modest decline. Maybe it's -- maybe we'll see production come off 100,000, and I think at the outside 200,000 barrels a day. But I'm of the opinion that they will plan a budget accordingly that supports levels at that point. And we'll see what actually happens going forward, but that's my expectation.

Right. No, I know it's too early to speculate, but I appreciate the thoughts, Ron. And then one question I had a follow-up on Marc's question on the power deliveries, right? I understand you're firming up the schedule. But I'm just trying to extrapolate what we heard on the Baker call earlier this week, they're booking a lot of orders. It seems like they're booking more orders than they have capacity right now, right? So I'm just trying to wonder, as you, at some point, think about, okay, should we at least get a slot, if not a firm order for deliveries beyond 400 megawatt. Any thoughts on what lead times might look like for that?

I think we're pretty comfortable saying that today with our partners on the power generation side, we can still expect deliveries in a 12-month time frame without any concern. In fact, we had a conversation literally the first part of this week to confirm what our additional opportunities would be for 2026. And so I'm quite confident telling you that if we were looking to add meaningful capacity to our order for next year, we could do that and expect deliveries in the same time frame that we are getting them today.

Okay. Okay. I got it. And very quickly, Michael, of that $575 million in CapEx that you gave us, how much of that is maintenance?

So a little bit -- it's a bit below $200 million.

Our next question will come from Grant Hynes with JPMorgan...

So despite some of the sort of pricing pressure that you kind of mentioned in the release in the lower part of the market, it seems like still kind of getting strong economics on the digiFleet rolling out. Maybe how should we just think of sort of go-forward cadence on digiFleets as we think about power CapEx largely spoken for next year? And I guess, any flexibility kind of on that side?

So I think, Grant, as we -- based on what we know today, we're going to finish out our digi program for 2025. Those fleets are committed to customers. They have a home to go to at contractual terms that we are very, very happy with. But as we look out into 2026, I think given our outlook today, there's a reasonable chance that we will retrench to effectively maintenance CapEx on the completion side of the business. that we would not deploy any additional digi capacity next year. Subject to change if market conditions change and we see a reason to make a move there. But at this point in time, I think we'd say that's our most likely outlook.

Got it. And then also, we've heard from some peers just on some nat gas activity being relatively stable. Obviously, I think some mix, but maybe with LNG facilities coming online, maybe seeing some early demand signals. I guess, can you just speak to this and maybe provide color if any of the equipment you were speaking about is kind of levered to gas stations?

That's a great point. Certainly not something we had mentioned, but we are in the fortunate position of being underweight Permian relative to rig count there and overweight Haynesville relative to rig count there today. So we are doing a good amount of work in the Haynesville. We're seeing strong support there and expect to see that continue through the latter part of the year, at least as best as we can tell today. So it has been a tailwind relative to the other parts of our operating platform.

Our next question will come from Derek Podhaizer with Piper Sandler.

I guess I just wanted to ask on the attrition comments you guys had in your opening statement. Maybe could you help us understand what you guys expect as far as moving diesel from the market? And you just answered the last question, not replacing much more digi as we look into next year. But maybe just help us understand the supply-demand dynamics of the industry and what you expect as far as diesel being removed and how that can help the supply and demand picture moving forward?

Yes. I think if you think about the market and even the commentary you've heard up to this point in time, I think you'll hear very consistently that there is strong demand for next-generation capacity and even the latest in dual fuel technology, specifically Tier 4. And then demand starts to fall off as you work your way down there. And so when we think about capacity that's going to end up with meaningful white space and ultimately probably sidelines, over the back half of this year and maybe even headed into next year, that's primarily going to be Tier 2 diesel capacity, maybe even a little bit of Tier 2 -- older Tier 2 dual fuel stuff. But I think the way you want to think about that is, as that stuff ends up on the sideline, particularly given a challenged economic environment like this, for those who are maybe finding themselves in a challenged cash flow position, the easy answer there is to cannibalize those assets for components to keep the core of the fleet running. You use the transmission, you use the power end, you use the fluid end, you use whatever might be helpful on there. And ultimately, you get to a place where that asset really just isn't worth bringing back into service. And so while we use 10% as kind of the average attrition rate on an annual basis, you go through years with really compelling economics where that number probably falls down into the mid-single digits, maybe even. And then you get to years like this where the economics are certainly more challenged. And it's our position that, that number will climb up probably into the mid-teens and that we're going to see an accelerated rate of attrition over the back half of this year and into '26. That ultimately sets us up for a much stronger rebound, a much tighter market, much quicker than you might anticipate when things start to turn around.

That's helpful and encouraging. Maybe just going back to the slurry pipe, pretty interesting technology. Can you help us understand maybe the total addressable market there? Is that just a Midland solution in the Permian given where the mobile mini mines are, the wet sand? Or could you move over to the Delaware? Or could there be anything outside of the Permian that we should be thinking about?

I think all of the above are certainly true. There's no reason we couldn't deploy it in the Delaware as well. There's definitely proximity mines over there. There might be advantages in terms of crossing state lines or whatever the case might be. I think there are opportunities across the Permian Basin. I wouldn't rule out a place like the Haynesville as a potential opportunity. We use wet sand there, and there may be a case where it makes sense in that environment as well. Certainly not something you're going to run in the dead of winter, of course. So that probably removes some amount of the geography. But outside of that, it's got real application over the right sort of distances.

Our next question will come from Eddie Kim with Barclays.

Just wanted to ask about the decision to reduce your fleet count and redeploy some of those fleets to larger customers with simul-frac operations. Is that because customers right now or certain customers are just kind of stopping completions activity altogether, maybe in response to the decline in the oil-directed rig count we've seen over the past 2 months? Or is it more because they're asking for pricing concessions at levels that are maybe unsustainable for your return threshold? Just any color there would be great.

There's probably a little bit of both of those. I think you could definitely find some smaller operators who are choosing to just stand down completions activity at this point in time. And there has been some reductions in activity. But there's also a real pricing challenge. I think we had some folks in the space who were facing already a calendar with a bit of white space on it into Q2, and they responded, we would argue, unconstructively in that regard with respect to price. And so we've seen some real degradation from a pricing standpoint in the market. And in some cases, that has us choosing not to participate in that. And so we would rather reallocate those resources in support of our strong long-term partners and help them drive efficiencies through things like simul-frac that are ultimately a win for both of us in this time.

Understood. Understood. And then just shifting over to the Oklo strategic alliance you announced earlier this week. I know it's really early days. But just based on your understanding of their sort of project timeline today. When do you think is the earliest you could see revenue from this partnership? Is it 2028 or maybe 2030? Just curious on your best estimate there.

Really, when you think about this one, Eddie, it's the same with any data center development, right? What this does is it allows the rollout of power -- early generation power to data centers as they build out in stages, right? And so I'd say you probably would see revenue on any of these large data centers sort of coming into '27 being anything of significance, right? And then from the nuclear powerhouses, you're probably in the early 30s when they are also generating, right? So you're going to build out your initial natural gas generation first, think of it in stages and then add in your nuclear baseload over time. At the same time, the nuclear baseload arrives, we will probably, on average, get close to having grid interconnection, which is then where we can then do the Liberty Chorus solution will kick in and we will manage the grid interconnection and the interaction between these large loads and the grid. So it's a combination of that. So that's sort of like the time frame in general. But what it will do is it will bring forward this ability. So you'll be to have these large load customers commit and have a road map to getting to some nuclear power, but without able to actually execute within an 18-month period from the first -- from signing a contract to powering a data house.

Our next question will come from Jeff LeBlanc with TPH.

The one question I did have is on mechanically these fleet repositionings, are you taking diesel assets to support gas burning assets? Or will the assets be upgraded before being redeployed? Or I guess, separately, are you redeploying some of your natural gas-burning assets to the simul-frac?

So we're not upgrading any assets at this point in time. Any of the older diesel equipment is headed for retirement at some point in time when that makes the most sense or potentially, I think, ultimately, if there's a home for that overseas, there's -- it may find its way there. But for us, we're not taking any of the Tier 2 diesel and turning that into Tier 2 dual fuel at this point in time. Our expectation is that our asset base over the long term will consist primarily of digi with some Tier 4 DGB backstopping that. And so as we think about the asset redeployment, that's just looking at the needs of our customers and making sure that we have the right assets in the right place to support their long-term needs. And so the operations team, the sales team working closely together to make sure that as we do this, we do this in a fashion that sets us up for the best possible success over the coming months and years.

As a speed to move to the simul-frac as well, that will be supporting in the short term as some of the digiFrac -- the rest of the digiFleet gets rolled out over the balance of this year. So it allows us to get to the simul-frac quicker. But ultimately, that's a temporary solution that will be replaced by the digi that come out in the second half of the year.

Our next question will come from Tom Curran with Seaport.

On the CS side, when it comes to the track operations, engineering and diagnostic tools, which offerings seem to be making the most difference when it comes to share gain traction or your ability to defend pricing here and there?

Well, there's a few things that play into that, and it really depends who the customer is that you're talking about. We have a range of customers who all have different end goals or different places where they need support or desire technology. In some cases, and I'd say particularly for the larger portion of our customer base, think those majors and large independents, it is generally a drive towards next- generation technology on location, backstopped by a strong safety record, great supply chain and some real innovations around the software side of things. So as we continue to advance our master rate control system, which we've been running in the field for more than a few years now, these things all are driving efficiency on location, getting jobs done quicker and just enabling them to get to a lower cost for a barrel of oil produced or an Mcf of gas produced. We have other partners, though, who lean heavily on us for our engineering support. So if you think about some of the smaller operators that are out there that maybe don't have all of that frac design expertise and capability inside of their shop, they are leaning very, very heavily on us, particularly in a time like this. One thing we always like to remind customers is that frac designs do not remain steady. The best possible frac design to put in a well changes depending on the economic conditions of the day. It might be that it makes more sense to pump a little more sand, particularly given where sand prices are today than it might have 24 months ago that there's a better return on that. And so we have customers who lean heavily on us from an engineering standpoint to work through that optimization effort with them. As one of the only companies, frac companies left that still maintains a strong engineering and geosciences team, we're the go-to partner for things like that. So it varies by customer, what enables us to retain that strong partnership and ultimately earn a bit of a premium working with that customer.

That's helpful, Ron. And then kind of shifting to the [indiscernible] side, 2 questions about the partnership with AltitudeX for the past project. Would you expect the eventual contract structure for LPI to allow for the sale of excess electricity into the wholesale market? And then compared to IMG's legacy PIT microgrid, I know that this past proposal envisages a system that initially will be nearly twice the size at 45 megawatts versus PIT 23. Cognizant of how early it is on the timeline, but what are some of the major similarities and contrast you would anticipate relative to the PIT microgrid? And in part where I'm going with this is, is there an effort to move towards and be able to demonstrate some degree of standardization that LPI will be able to offer?

Yes. So the -- if you think about the PIT microgrid, right, that is based around a modular power generation solution, right? Each one of those powerhouses comes on 3 different trucks and within a 24-hour period to be craned into position. And so -- and then there's about 6 weeks of total commissioning after that. So you could get to the fact of about a 2-week -- once you've done all your site work and your footings, et cetera, you can get to about a sort of an offload situation where you're sort of about 2 to 3 weeks of construction and connection with all the quick connects. And then you get to sort of about a 6-week to 8-week commissioning cycle, right? So it's a very standardized modular process. We're bringing that to all of the products we do. And so very much about the [indiscernible] product will be based around that similar sort of solution. Now it could be a combination of different generating technologies, right, whether it's the [indiscernible], that we run at the pit solution or the Caterpillar ones, which are a slightly smaller one that we've used as a base for our frac, which are about a 2.5 megawatt as a baseload, but very much the same modular construction, which takes a lot of the risk out of the construction and a lot of the -- everything is done and tested in a factory. And therefore, you take a lot of the need for trades out of the field. So it also reduces -- significantly reduces the cost and time of implementation. So very much the [indiscernible] product -- project or even the data center projects that we are bidding at the moment, very much based around that solution. Think of it as like modular LEGO blocks and we can build to a power plant of any given size right. Now as we get up into the larger and larger projects, we may use a slightly larger power generation unit than the 4.3 [indiscernible] or the 2.5 [indiscernible] we may move up to sort of a 10-megawatt. And eventually, we will use package turbines depending on fuel source and power density requirements. But ultimately, the philosophy is very much what you see at the Pittsburgh Airport that very much as much as possible packaged in a factory and brought to site to speed the implementation. Integrated with the grid, most definitely, the offtaker of [indiscernible] will actually be most likely sort of a -- sort of local utility, cover the Adams County side of that organization. And so yes, we will be able to -- for all of our industrial sites that we are developing, we will be able to wheel power onto the grid and provide local grid support into the wholesale market.

Our next question will come from John Daniel with Daniel Energy Partners.

Ron, sort of an ops question for you. Historically, we always thought of the Haynesville being a terrible wear and tear on the frac equipment. And I'm just curious, does that same wear and tear effect apply to the new generation technology like your digiFleet.

John, you're absolutely right. That is a very high-intensity environment. It is high rate, high-pressure work. And there are only some who are successful in deploying technology there and being a successful partner. We have made tremendous strides there. And certainly, we have seen to this point in time with our next-generation assets, just a real change in asset life. And that's true in high- pressure, high-intensity environments as well. I would say there are probably a couple of reasons for that. One is that we've designed the asset specifically for that type of workload. It's designed to handle the flow rates that we're putting through that. And of course, digiPrime in eighth gear, we're delivering 12 barrels a minute out of a single pump. So probably twice the rate we typically send out of a more traditional pump. But you have a pump that was designed with that very idea in mind. It's not like we took some existing technology and then tried to cram some more through it instead. We have from the ground up an asset designed to handle that rate and pressure. And then in parallel with that, of course, we've been working very, very hard on the asset monitoring, digital twin and AI oversight of our entire asset base. And I think that has also played significantly into our ability to extend the life of these components. We have the hive here in just northeast of Denver, staffed with the team 24 hours a day and maybe more importantly than that, they are supported by a sophisticated set of algorithms that's monitoring the second derivative of every data stream that we collect off of an engine transmission power and/or pump and all the other components that are out there, and we are finding things before they become an issue. We were able to see that change in the trend, identify that to the crew in the field, make a minor repair instead of a major repair, and that really has gone a long way in terms of extending asset life as well. So I'd say you layer that on top of a next-generation fit-for-purpose asset and you get these incredible performance improvements that we have seen.

Our next question will come from Dan Kutz with Morgan Stanley.

So maybe just on the -- going back to the international opportunities. I know you guys are doing work in Australia. For any of kind of the future international deployments of some of the Tier 2 assets, as you think about those opportunities, is Australia the only market that you guys are looking at or looking at some of the other unconventional basins like Argentina or Middle East? And then I'm not sure if you quantified this before, but anything you could share on kind of the cost to ship a fleet internationally and kind of staff up and deploy that fleet, and I guess, any kind of associated upgrade cost? Just wanted to check in and get a better picture on the international opportunities.

Yes. Of course, we continue to look at all the opportunities around the world. And we get inbound from all over the place, as you can imagine. The Middle East is a common spot where we get inquiries from. Argentina has been on the radar screen of late given the change in government there and the success that has brought in the country. And as a result, expected real uptick in activity in [indiscernible]. So we continue to keep our eyes on all of these opportunities. And I would say even over and above that opportunities for growth in Australia as another place. So we're on the ground there, of course, we've got our fleet there. We're doing work in the Beetaloo Basin, but Australia is recognizing that they need more gas and they need more gas onshore Australia. That's leading to some support for unconventional work not only in Beetaloo, but elsewhere, particularly in the Queensland area. So we are engaged in all of those conversations. And when we see opportunities that make sense, we are certainly prepared to take some of that capacity and go to work there. I'd say as to cost, obviously, that's going to depend on where we go. Going to a country like Australia comes with very stringent requirements around importing an asset there. You were not allowed to have a spec of dust on a piece of equipment to get through customs when you arrive in Australia. And so -- those assets were completely refurbished. They were scrubbed down effectively with the toothbrush to make sure that they were absolutely spotless when we arrived in Australia and that we ran into no customs issues there. Of course, that's not the same case in all the environments we might visit. So you're going to see that number vary a fair bit. But you could be rest assured that we are not a company that's going to send a substandard fleet of equipment someplace to do work. We go there to be the best at what we do. We go there to excel at what we deliver. And so we're going to make sure that we put a fleet on the water that is up to the standards of the work we're going to be doing there. So there's an investment that goes with that for sure. Obviously, not the cost of a new fleet, but there's a refurbishment cost that's attached to that.

Got it. Understood. That's really helpful. And then maybe just one on shareholder returns, and apologies if I missed this. Is kind of the read now that I know you guys didn't do any buybacks in 2Q. Is -- how do you think about weighing potentially picking up some shares at an attractive valuation and the other capital allocation priorities that you have? Or is maybe kind of the balance sheet a governor on shareholder returns like you guys are open to it, if there's some excess cash after the other capital calls have been satisfied. Just how do you think about share buybacks at this point?

Yes. Of course, we think about share buybacks the same way all the time, which is an opportunistic approach to them. When the greater the dislocation between our stock price and what we view as the intrinsic value of the company, the more apt we are to be involved in the market. The last quarter, of course, a pretty volatile one, and we wanted to make sure that we had our feet underneath of us that we had a good look ahead as to what was coming and that we were well set up and well positioned to navigate that whatever it might be and to take advantage of any opportunities that might come in front of us. Of course, we've been opportunistic both in the '15, '16 downturn and in the COVID downturn. We had tremendous opportunities there that really took the company to another level. We want to be ready for those such that they might appear. And so yes, we took a short gap in the second quarter just to stand back and understand the landscape, make sure that the balance sheet was well set up for whatever the future would hold. And as we look forward, of course, we'll continue to look at our stock price and whether or not that is the best use of some cash as we move through the balance of the year. Michael, anything to add there?

No, I'd just say one of the key things there is that investing in growth has really got a great potential to increase our long-term EPS power of Liberty's earnings. And that really drives the greatest value over time. And we've got some great and exciting growth opportunities in front of us.

This concludes our question-and-answer session. I would like to turn the conference back over to Ron for any closing remarks.

Thank you. Global oil demand grew by 0.7% last year, supplying 34% of global energy needs. Global natural gas demand grew by 2.5% last year, supplying 25% of global energy needs. Electricity demand grew by 4%, outpacing total energy system demand growth. We have a similar power story unfolding here in the United States, driven by growth in AI and a reshoring of manufacturing. Recognizing that we had a bigger role to play in delivering on our mission to better human lives, we changed our name from Liberty Oilfield Services to Liberty Energy in April of 2022. We subsequently made investments in small modular nuclear through Oklo, in enhanced geothermal through Fervo and in batteries through Natron. We have worked hard to ensure that the critical role oil and natural gas play in the global energy stack is recognized and that their continued development is supported by the regulators, the public and the financial community. And we are committed to continuing that important work. Unfortunately, our electricity grid has suffered due to similar challenges, misguided policy, market distorting financial incentives and pushback against major infrastructure build. But with that comes opportunity. We're energized by this next chapter of the Liberty Energy story and as a champion of abundant, reliable power to meet the growing needs for electricity in the U.S. and as a key provider to consumers of the advanced distributed power services necessary to support their business. We look forward to the years ahead. Thank you for joining us on the call today.