Liberty Energy Inc. (NYSE:LBRT) Q2 2024 Earnings Call Transcript

Liberty Energy Inc. (NYSE:LBRT) Q2 2024 Earnings Call Transcript July 18, 2024

Operator: Welcome to the Liberty Energy Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today’s presentation there will be an opportunity to ask questions. Please note, this event is being recorded. I would now like to turn the conference over to Anjali Voria, Director of Investor Relations. Please go ahead.

Anjali Voria: Thank you, Gary. Good morning and welcome to the Liberty Energy Second Quarter 2024 Earnings Call. Joining us on the call are Chris Wright, Chief Executive Officer; Ron Gusek, President; 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 views 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 not measures include EBITDA, adjusted EBITDA, adjusted net income, adjusted net income per diluted share and adjusted pre-tax return on capital employed 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 the calculation of adjusted pre-tax return on capital employed as discussed on this call are available on our Investor Relations website. I will now turn the call over to Chris.

Chris Wright: Thanks, Anjali. Good morning everyone and thank you for joining us to discuss our second quarter 2024 operational and financial results. Before we begin, I’d like to recognize our Houston-based colleagues that were impacted by Hurricane Beryl. Many were left for several days without power but they rose to the occasion to meet the needs of our business and support each other and the broader community with remarkable resonance. I want to thank them for their exceptional efforts. In the second quarter, Liberty delivered strong operating and financial performance, demonstrating the value of Liberty’s competitive advantage. Revenue of $1.2 billion and adjusted EBITDA of $273 million grew by 8% and 12% sequentially, respectively, while industry drilling and completions activity modestly softened over the same period.

Record average daily pumping efficiencies and record safety performance, coupled with increased utilization of our fleet underpinned the strong results. Our company culture long-term customer partnerships, innovative technologies, scale and vertical integration allowed us to deliver 28% adjusted pre-tax return on capital employed for the 12 months ended June 30, 2024. We generated strong cash flow and distributed $41 million to shareholders in the second quarter. Since the reinstatement of our capital return program 2 years ago, we have distributed $458 million of cash to shareholders through the retirement of 13.2% of shares outstanding plus quarterly cash dividends. We plan to continue strategically deploying capital to expand our competitive advantage and leadership position, while returning capital to shareholders.

Our culture of innovation and Liberty developed technology are at the root of our success to date and the key to our future. This is reflected in today’s highest-ever operational execution and safety performance over our 12-year history. We are driving performance by harnessing data and software solutions throughout our organization. Three specific examples are: one, our record diesel displacement with data analytics driving enhanced gas substitution; two, our preventative maintenance programs, extending asset life performance and reliability; and third, Liberty’s custom-built AI-empowered logistics software platform we call Sentinel. Before I highlight these 3 specific innovations, I want to remind everyone that Liberty alone has designed and deployed our own custom pump technologies and power generation technologies that allow us to optimize fleet arc type [ph] for performance and capital efficiency.

Most importantly, we have built a culture of accountability and awareness around safety that we ceaselessly strive to improve. We have driven a 25% reduction in recordable incidents TRIR over the last 1 year alone, down to roughly 50% below industry averages. I’m very proud of this fact. I believe we are the most competitive, most efficient frac company in the sector. Let me add a few more comments on our recent technology-driven enhancements. Our diesel displacement is now at the highest level in the company history from both the deployment of our natural gas fuel digiFleet and record gas substitution with our dual fuel equipment. Over the past year, dual-fuel gas substitution levels have increased over 25% for three reasons: investment in automated operating systems, increased expertise and visibility with real-time data on critical gas parameters, plus the coordination made possible by our addition of Liberty Power Innovations to supply on-site natural gas.

Our predictive and preventative maintenance program, coupled with data visibility and analytics allowed us to increase uptime and run assets at optimal operating ranges, both for frac performance and to achieve maximum gas substitution. We further enhanced our LPI portfolio with the commissioning of our operations in the DJ Basin, including compression capacity and logistics assets with first CNG sales in June, serving Liberty fleets and customer drilling — vertical integration drives efficiency. It is hard to overstate the impact of our advanced Sentinel logistics platform, harnessing real-time data and AI predictive analytics to both precisely forecast on-site proppant demand and inventory and then optimize transportation and logistics. Since inception, we have reduced our already very low downtime due to proppant delivery by 90% and we decreased the truck count and delivery time by approximately 35% each improving collaboration with supply chain partners and ultimately lowering the total delivered cost for our customers, less assets, less time and improved performance.

That is why we built the Sentinel system. We launched the known Permian approximately a year ago and have now expanded to all U.S. basins, now focus on deploying sentinel logistics solutions across our LPI CNG business. Sentinel is a key tool as we expand our business going forward. We strive to deploy the right technologies at the right time for the right reasons. AI is yet another tool that we are now utilizing to enhance our operations. AI comes full circle for us, the massive increase in data centers for AI and restoring industry back to the U.S. is inflecting upwards demand for electrical power and natural gas. AI is both enhancing our business and growing the demand for our services. We are excited by the potential opportunity to meet that demand through our LPI business.

Our LPI business is starting in the oil field, where we are building assets and expertise to reliably deliver both natural gas and electricity 24/7 in remote areas. On frac locations, we rapidly construct a 25 to 35-megawatt power plant, fuel and operated and then tear it down roughly once a month and move that plant somewhere else. Our technology, assets and expertise are positioning us very well to expand the playing field for LPI. Global oil and gas markets remain constructive on favorable multiyear market fundamentals, despite near-term volatility in commodity prices. In June, a decision from OPEC+ to gradually unwind voluntary production cuts beginning in October, drove oil prices lower. Even then, prices were well above those supportive of attractive E&P returns.

Oil prices have since recovered on relatively balanced supply and demand dynamics, owing to relatively resonant global economic growth and a rising demand for transportation fuels with summer travel season underway. Natural gas prices saw a resurgence from early spring lows as gas producers reduced drilling and completions activity and curtailed production. Recent reinstatement of some curtailed production has moved prices downward but still above recent cycle lows. The commissioning of new LNG export facilities and continued growth in power demand are expected to drive higher natural gas demand and eventually firmer natural gas prices than today’s. Frac industry trends have moderated marginally in recent periods, on the heels of slightly softer drilling activity in both oil and gas basins during the first half of 2024.

Industry-wide completions activity has declined to levels consistent with approximately flat oil and gas production. For the U.S. to deliver rising oil and gas production levels, completions activity would need to rise. Signs of tightness for quality frac crews may emerge in 2025 on a demand pull for energy. The attrition of older equipment from higher intensity fracs with increased horsepower requirements is reducing the available horsepower to meet an eventual increase in frac fleet demand. As E&P operators continue to consolidate, their efforts are focused on efficiency gains through partnership with service companies that can deliver superior performance and provide technical solutions to create value. Liberty’s’ supply chain has continued to rapidly innovate and drive efficiencies in procurement, manufacture and delivery of essential materials for frac operations.

The resulting efficiencies benefit both our customers and our business. Liberty’s digiTechnologies, LPI services top-notch supply chain, scale and integrated services enable us to drive improvements across the board for our customers and grow our industry competitive advantage. As we continue to execute on our returns-focused value proposition, we are well-positioned to deliver strong financial and operational performance. Our strategic investments deepen our portfolio of natural gas fueled pumping and power generation technologies, driving higher earnings and cash flow generation potential. Industry conditions moderated through the first half of this year. We now anticipate the total North American completions activity will be modestly softer in the second half of the year, due to budget front-loading by some operators.

However, we expect Liberty financial performance to be similar in the second half of the year compared to the first half. We expect to continue investing in our competitively advantaged portfolio, deliver healthy free cash flow and return capital to our shareholders. We are committed to safely and responsibly creating long-term value for our partners and shareholders. With that, I’d like to turn the call over to Michael Stock, our CFO, to discuss our financial results and outlook.

Michael Stock: Good morning, everyone. I’m pleased to share that we have delivered solid financial results for the first half of the year, despite softening industry conditions and activity levels. Our teams came together to drive outstanding efficiencies during the second quarter, safely delivering more pump hours, more stages and pumping more proppant than ever before. We have made significant progress on our investment strategy, designing and delivering next-generation digiTechnologies that are in high demand, while expanding our LPI infrastructure to ready ourselves for growing natural gas demand. We have also continued to deliver on our capital returns program. 2 years in, we have now returned $458 million to shareholders, predominantly in the form of accretive buybacks.

We expect to continue to execute on these initiatives for the remainder of the year. In the second quarter of 2024, revenue was $1.2 billion compared to $1.1 billion in the first quarter. Our results increased 8% sequentially, as accounting efficiencies and integrated services offset lower sand and other consumable prices and market headwinds. Our teams produced record pumping hours, record stage counts and record proppant pumps bucking the trend of industry activity declines. Second quarter net income after tax of $108 million increased from $82 million in the prior quarter. Adjusted net income was $103 million compared to $82 million in the prior quarter. In recent years, we have made investments in several energy companies such as in Oklo and Tamboran, that have potential to help meet the world’s growing demand for energy.

Oklo and Tamboran, both commenced trading on the New York Stock Exchange during the second quarter and resulting in a net unrealized gain of $7 million before taxes. As a result, we’re providing adjusted net income to exclude items outside our normal operating results to provide a more useful measure of comparison for net income from period-to-period. Fully diluted net income per share was $0.64 compared to $0.48 in the prior quarter. Adjusted net income per diluted share was $0.61 compared to $0.48 in the prior quarter. Second quarter adjusted EBITDA was $273 million compared to $245 million in the same prior quarter. General and administrative expenses totaled $58 million in the second quarter and included noncash stock-based compensation of $5.

G&A increased $5 million sequentially primarily on higher compensation expense, annual salary adjustments and other miscellaneous expenses. Other income items totaled $1 million for the quarter, inclusive of the aforementioned $7 million net unrelated investments. Excluding these gains, net interest expense of $8 million was relatively in line with $7 million for the prior quarter. Second quarter tax expense was $33 million approximately 23% of pre-tax income. We continue to expect tax expense rate in 2024 to be approximately 24% of pre-tax income. Cash taxes were $8 million in the second quarter and we now expect the 2024 cash taxes to be a maximum of 70% of our effective book tax rate for the year. We ended the quarter with a cash balance of $30 million and net debt of $117 million.

Net debt declined by $25 million from the end of the first quarter. Second quarter uses of cash included capital expenditures, $30 million in share buybacks and $12 million in quarterly cash dividends. Total liquidity at the end of the quarter, including availability under the credit facility, was $271 million. Net capital expenditures were $134 million in the second quarter which included investments in digiFleets, LPI infrastructure, dual fuel fleets, upgrades, LAET, Liberty Advanced Equipment Technologies, facility construction capitalized maintenance spending, accelerated maintenance on spending on our fleet in transit to Australia and other projects. We had approximately $2 million of proceeds from asset sales in the quarter. We now expect capital expenditures to be around the high end of the range for 2024.

Also in the quarter, we invested $16 million in the B2B Basin operators to support this exciting new source of natural gas for the world. Our ability to generate strong cash flows through cycles enables our commitment to capital returns. In the second quarter, we repurchased $30 million of shares or nearly 1% of the shares outstanding and distributed $12 million in cash dividends. We continue to deliver on a return of capital program, while reinvesting in high-return opportunities that increase our long-term cash flow generation. While we have seen a slight moderation in industry activity through the first half of the year, Liberty has mitigated these impacts by focusing on meeting the increased complexity of our customers’ demands. We have been able to leverage our technology investment, scale, integration and focus to drive superior results.

While continuing to build our competitive advantage, in the second half of 2024, we now anticipate flattish financial results but largely mirror the quarterly cadence of the first half of the year. We’re also expecting digiTech deployments to continue ratably throughout the year and are on track to end the year with close to 90% of fleets primarily powered by natural gas. I’ll now turn it back to the operator for Q&A, after which Chris will have some closing comments at the end of the call.

Q&A Session

Operator: [Operator Instructions] Our first question today is from Scott Gruber with Citigroup.

Scott Gruber: Chris, can you provide some color on pricing trends across the various frac technologies today. Investors have been asking whether the Tier 2 pricing is just getting so wide kind of versus DGB and e-frac that it’s starting to exert some negative pressure on those newer technologies? What do you guys see in the marketplace today?

Chris Wright: Yes. Look, as we said, Scott, the market is — the activity level is slowly declining which I would say is making the market slowly softer, modest changes slowly. And look, this has been going on for almost 2 years now from the peak activity in late 2022. And of course, if you’ve got your choice of frac technology and you do today, a straighter Tier 2 diesel engine, that’s the lowest choice. That’s the oldest equipment. It doesn’t burn the gas; it’s more expensive to fuel. And so for the larger operators with large steady programs, there’s very little of that technology still employed. But you’ve got a lot of smaller companies that don’t have a full fleet program but they’re still spending significant CapEx. That’s where most of the Tier 2 diesel frac equipment is operating.

But yes, that market is softer. And I think you’re seeing the fading away of Tier 2 diesel engines. They’re not going to all be gone for probably still several years but yes, they’re declining. The desirability of them is lower. But again, still many of those fleets running, including from Liberty.

Scott Gruber: Got it. And how would you describe the incremental demand for e-frac. How far out are your fleets contracted are 9 to 10 spoken for? Are you starting to have the discussions on the early fleets for next year. I’m just kind of curious about the how those discussions are going? And how far out are those discussions today?

Chris Wright: Yes. There are ways out. Look, everything we’re ordering equipment for looking to construct in the next year, that’s spoken for. And we’re in discussions with many others, more than we can supply for fleets that might deploy or start in first half or middle of next year. So that’s a ways out. That next-generation equipment, not only is it cheaper to run because it’s burning all-natural gas versus on the extreme old diesel or some mix of the 2 but it’s quiet, it’s precise, it’s high tech. I mean demand for that is quite significant.

Operator: The next question is from Marc Bianchi with TD Cowen.

Marc Bianchi: I wanted to ask Chris on your outlook for sort of the progression into ’25, you sounded kind of constructive on the direction of demand just based on where oil production, gas production are at current frac levels. But if I look at what E&Ps are doing just with being in maintenance mode and consolidation and efficiencies that are happening, like they’re not looking to grow in ’25. So is it that you see them changing that plan? Or is it something coming from private? What are you seeing that kind of gives you the optimism about growth in ’25?

Chris Wright: Yes. And look, I would say our expectation for growth in ’25 is likely modest. But the current activity today, it would not support even flat natural gas production because it overshot, it overshot. We had very robust gas activity — in through 2022, I thought that would roll down more in early ’23 but it really didn’t roll down until later in ’23. So gas activity is very low right now. That’s — and that’s not going to reverse next quarter. probably not this year. But as you look ahead, eventually, you’ve got to have more activity just to keep U.S. natural gas production flat, let alone a little bit of growth. We have to be careful, of course, of too much growth which has been the mistake in the past in — among the natural gas operators.

And today’s oil production is also pretty flat. We had a chunk of growth last year. But crude production, it’s been flattish for 6 or 8 months. And we’ve still seen activity decline a little bit since then. So the production trends you’re seeing today, that’s reflective of what frac activity was 3 to 6 months ago. We haven’t seen a production trend reflective of today’s frac activity. It’s probably flat at best oil production. So again, I’m not predicting a big change next year. But this second half of this year is going to be a little softer than the first half. And the first half of next year will likely be back up, I would say, at least to the levels of the first half of this year. So we’re not expecting a huge rebound. But from where we are today, I will see an increased activity in the first half of next year.

Marc Bianchi: Yes. Okay. And those are kind of market comments, not necessarily Liberty comments but maybe you sort of follow that trend.

Chris Wright: 100%. Those are market comments. Look, as we said, we’ve had a meaningful, probably 25% to 30% decline in active frac fleets industry-wide, from 2 years ago to where we are today and Liberty is basically flat through that period. So yes, we have not followed the industry trend. We haven’t added fleets. We don’t want to put anything into a soft market. But the interest or desire among operators to work with Liberty is high. And look, the biggest reason for that is just performance. The operational performance of our teams and the way we do business. Second after that is high-tech and next-generation equipment. But those things keep demand for Liberty high but again, yes, as conditions soften, you won’t see an increasing fleet count from us but we haven’t reduced it as we thought we might, just the customer demand and to continue the relationships has been quite strong.

Marc Bianchi: Yes. Yes. Makes sense. And then just one more on kind of the near-term progression. So if second half is going to be similar to first half, is the right way to think about it that from an EBITDA perspective, third quarter looks like second quarter and fourth quarter looks like first quarter, so essentially a mirror image. Is that what we’re talking about?

Chris Wright: That’s exactly our guess. That’s our guess. And of course, we got a pretty good view into Q3, yes which looks flattish. And Q4, you don’t know but that would be our expectation. It’s probably similar to Q1.

Operator: The next question is from Arun Jayaram with JPMorgan.

Arun Jayaram: Chris, I was wondering if you could kind of elaborate on some of the trends and growth initiatives you have for LPI and what kind of demand trends you’re seeing for that offering?

Chris Wright: Yes. So again, huge interest there as well. Look, there’s just this massive cost savings to burn natural gas instead of burning diesel. And then the question is how do you do that? That’s been going on in the industry for, geez, I mean, second fleet, we built with dual fuel. So it’s been going on for at least a dozen years. But it’s been, hey, we’ve got gas on location. We can power most of the pumps or all of the pumps but we’re down for a while on gas but we’ll just burn more diesel; and so it’s been there. What we’ve tried to do is just set that bar higher, that if we’re planning to burn dual fuel there, we’re going to make sure we have reliable gas supply to every pump that’s operating on location and up and down with the trends in that frac activity.

And because you have to have reliable gas to maximize the displacement of diesel. So that trend just continues. As we were talking, the straight diesel fleets are declining in their percent market share. And so hence, there’s just more, every month, there’s more gas burned for hydraulic fracturing operations than there was the month before that. We launched that business in the Permian. We still have a lot of growth in the Permian. We are just, as we announced at our thing just kicked off in the DJ. We’re doing some work in the Haynesville as well. We’re not in the other basins Liberty operates yet but we will with time. Most of our gas is to operate our own frac fleets but we’re also supplying customer rigs. That will broaden into other industry applications.

And look, as you get into next year, that sort of virtual pipeline will broaden into just powering electric generating assets even outside of our industry. I don’t think we see that until next year. There’s just so much growth and so much to be done within the industry first. But yes, we’re, there’s just huge, huge running room for that business.

Arun Jayaram: Great. And I had a housekeeping question on the balance sheet maybe for Michael. Michael, can you walk us through the capital lease item on the balance sheet which — looking at it right now, it’s $236 million, what is running through capital leases versus CapEx?

Michael Stock: Yes. So — we’ve run a number of things through capital leases. Generally, it’s rolling — some rolling stock. The interest rates on capital leases are actually sort of lower than — slightly lower than our ABL facility at the moment. So it’s a very, very effective way of sort of arbitraging kind of a short-term term loan to fund some of the kind of moving stock that we roll.

Arun Jayaram: And what would you like characterize as that moving stock? Just a little bit more elaborate on that?

Michael Stock: Tractors, CNG trailers, things are of that variety.

Operator: The next question is from Jeffrey LeBlanc with TPH.

Jeffrey LeBlanc: For my first question, I wanted to see if you can give us an update on how much of your capital expenditure is allocated to LPI this year. Additionally, given that the LPI value chain extends beyond mobile power generation and historically, the $60 million stake [ph] price for digiFleet included power generation, how should we be thinking about the megawatt capacity that will be in operation by year-end?

Michael Stock: So if we take that one, I mean we’re running about 125 megawatts of power generation at the moment. We have probably about a bit more than 50% of that under construction for our future power generation in the oil field. Obviously, that doesn’t include virtual megawatts that we use with digiPrime. LPI, the vast — the majority of the CapEx that’s being spent at the moment is on moving the molecule. So we’re really managing the molecule to the frac fleets which increases uptime, increases efficiency and increase substitution rate. So that comes in the form of CNG trailers. The compression that we built in the DJ Basin, fuel distribution on site, field gas treatment for a number of our larger clients that have fuel gas in the field.

So really kind of an integrated solution to be able to sort of manage the molecule into basin — either power or to drake drive the pushing stuff downhill. So that’s the majority. We don’t break the CapEx out between that because again, single segment and it’s all related to frac. In a power generation outside the industry, outside oil and gas, we’ll probably talk about maybe in the next call as we look at those but that will be something that we will discuss separately for power generation for non-oil and gas operations.

Operator: The next question is from Stephen Gengaro with Stifel.

Stephen Gengaro: I’m not sure how much you can break this out but I’ll ask. When we think about — Wall Street still does this — done math, right? We divide EBITDA by fleet or revenue by fleet to get a number. When we think about your revenue or profitability per fleet versus, say, 2 or 3 years ago, is there any guide you can give us kind of — and how much of that is pure frac and how much of that is driven by either a mix of newer frac assets and/or LPI and other integrated services?

Michael Stock: Let me just take that one, Steve. The reality is we’re a single segment, right? So everything is frac or everything we do is focused around supporting frac. So it is all related. But you are right, just for the investors to think about the frac. We’ve talked a lot about over the last 5 years, our expansion and our vertical integration, right? You think about it, the factor. We own sand mines. We’re doing gas delivery. We own manufacturing, we’ve dropped out our maintenance cost. We’re building a new manufacturing facility in Oklahoma to where we’re going to actually building some of our digiPrime and some of our power generation equipment to help support the — our partners that have historically put our equipment together, assembled our equipment because there’s just not enough capacity.

We own that design from everything from the design to the BOM [ph] — the actual manufacturing instructions. And that helps bring more efficiency into the building of our equipment. So all of our investments, you think about that, single investments in our sort of logistics software, we move about 1 million, approximately around about 1 million truckloads of sand a year. I think somewhere in that route. There’s a huge investment that we’ve made in this vertical innovation, most of sort of the — our clients come to us to provide their sand, to provide their chemicals. So we are able to basically mine more of the value chain. If you go back all the way to the period before the OPEC war on shale, there was so many layers of profitability. So many people are at the trough, taking profit out of the system, right?

So we’ve got larger clients now wanting larger oilfield service fees and provide more of the services, more complex, more integrated which means more of the wallet share stays with us. And that’s the unique Liberty sort of investment that we’ve done is that we take everything. If you think about digiFrac, we own the power generation. We own the gas delivery. We own the pumps. We are the only company that has that whole value chain and makes returns off that whole value chain. And that is the difference. Hence, the reason. It’s all supporting frac. It’s all about the teams that are operating at the wealthy but we make money through that whole value chain, Steve.

Stephen Gengaro: Great. That’s very helpful color, Michael. And this is a follow-up to that. Recent Kimberlite recent survey came out and we were speaking with them recently. And one of the things that stood out to me was there’s 2 companies that have completed — are completing wells in 7 days or less. If you were in one of your biggest competitors. I was just curious, what drives that? Is that the overall integration of the fleet? Or is that just your highest end digital assets that are kind of driving your ability to kind of lead on that front?

Chris Wright: Look, I’m going to have Ron answer that question. But the short answer is the humans, the people that run Liberty frac fleets. That’s the biggest differential and just that attitude about how to coordinate the symphony to deliver. But I’ll let Ron elaborate a little more about the technologies and how this is all done but really, it’s culture in humans.

Ron Gusek: Yes. Stephen, I think Chris hit on the biggest point there, you’ve always been focused on culture since the beginning and creating an environment where people wanted to come and make a career out of it. And I think that’s been demonstrated in our performance now for 13 years, I guess. Hard to put a value on that but I think it plays out very, very well in that Kimberlite report and the response from our customers there around the service quality they get. But then I think all the points Michael made earlier pile on to that to help support that. Of course, we deliver great service in the field but that’s supported by industry-leading technology developed in-house here at Liberty and support by a team here at Liberty.

It’s supported by a world-class supply chain organization that ensures we have multiple legs on the stool that, of course, we have some amount of internal support, whether that’s manufacturing or sand or things like that. But also great partners from the third-party side that are also helping to assist in that, ensuring we never are short sand or short chemical or without a part in the field or anything like that. You layer on top of that the work we’ve done in artificial intelligence in terms of understanding both the operation and performance of our equipment, the ability to predict when — in advance of something going that we need to take care of some maintenance there, maximizing uptime we’re seeing on location with the assets each and every day.

We have a maybe unrivaled level of visibility into our operation in the field now, not only for the equipment itself but as Chris talked about in his opening comments, Sentinel Logistics platform and our supply chain for ensuring that sand and chemical arrive there on a timely fashion. And then I think, as you think about the scale of our organization now, one of the other things that we’ve always been focused on is engineering support. So we have engineers out on every location. We have a strong engineering team here that is working side-by-side with our customers to optimize completion design out there as we continue to improve and that remains an important piece of the puzzle is as we continue to migrate from acreage of some quality to acreage of maybe a slightly lower quality but ensuring we have a completion design that is optimal for that.

And so you continue to layer all of those things on and we continue to find ways to be more and more efficient out on location every day.

Operator: Next question is from Waqar Syed with ATB Capital Markets.

Waqar Syed: Chris, this is kind of a big picture type question that I’m asking. And I’m going to throw out some numbers here. And if I look at this quarter compare it to the year ago quarter, your revenues are down only 3% but your EBITDA margins are down 240 basis points. EBIT margins are down about 70 basis points. DD&A — quarterly DD&A is up about 25% and return on capital employed is down from about 30% to 20%. Now having said that, these are still best-in-class results, 20% return on capital employed is still very, very attractive. But it does feel to me that all the value that you’re adding, all the investments that you’re making, efficiency gains, a large portion of that benefit is accruing to the customer and you’re not getting the fair share that really, your effort really entails.

Is there a new type of contracting structure that you could think of performance base? Or you’ve seen some of the drilling contractor’s kind of pursue that. Is there some other arrangement that pumpers could make where they’re making so much investment, so much effort but probably not fully getting the benefit of that?

Chris Wright: So Waqar, that’s a reasonable overview of the numbers. And I think the short answer there really is the business remains cyclical. What’s nice is that the cycles now or at least this cycle is much more mellow than previous cycles. We’re “wow, we’re killing it” and then OPEC frac shale and things collapse for a while and it bounces back. So what all those numbers you were counted or that the business conditions have been softening for nearly 2 years. And that’s — we’re probably near a bottom. They’re not changing much right now. But yes, 2 years ago, the business conditions were fantastic. Today, they’re weaker. And if you look across the whole industry, you’ll see a pretty big swing — a much bigger swing down than you’ll see in Liberty in that but it’s still a slower, more modest cycle.

And so that return on capital employed, that denominator, yes, we have new assets. Most of these assets are 10-plus-year assets that we’ve just built. So all the cost is there burdening us. But when we make these investments, we’re thinking over the cycle, what is the — what is the return we’re going to get on those assets over the next 10 years. That’s what drives our investment decision whether to do them or not. Because you can’t just turn that spigot on the conditions are a little weaker, let’s stop all investment or conditions are great, let’s hit the gas and whatever invest at a super high rate. That’s just — we always are looking at it longer term, longer game for investment decisions. We do with our partnerships with customers, we do have performance-based stuff built in a number of our contracts.

How can we get better together and how can we win together on that? We don’t talk about that stuff because it’s individual fleet-by-fleet or customer-by-customer. But are we looking at ways to tie are forcing together and to get better returns on our investment, absolutely. But the numbers — the whole team look at is what is the investment over the long-term in our assets. And in fact, we may read that the numbers you just recounted a little different and say, wow, we’ve been rolling down almost 2 years and our average return on today’s assets, still pretty strong. And so — but yes, what you’re seeing is not really a secular change in contracting and how the industry works. It’s just the effect of a slow modest cycle. But great question, Waqar.

Waqar Syed: Okay. And just if I may ask another a slightly different question about completion activity into next year. If you look at the supply/demand, commodity price forecast from EIA, IEA or OpEx period, they’re all projecting U.S. oil production to be — or liquids production to be up like 5,000 to 6,000 barrels a day year-over-year in 2025. Do you think, what kind of activity — completion activity increase would it be required to get to those kind of production growth numbers?

Chris Wright: Well, modest but definitely an increase, definitely an increase from where we are today. Again, I don’t think it takes a lot of change in increased demand to change the feel of the business cycle a bit. I would say that at probably this year’s investment levels, I’d love to look back at this whole year. We’re probably going to see a slight shrinkage in the available supply of frac equipment. There’s a lot of Tier 2 fleets still running that are not being reinvested and that are shrinking. There’s new gas-powered fleets being built but likely less this year than the attrition or wearing down of fleets. So cyclically, the market — the investment levels are relatively modest. But so if you have even just a 5% or 10% increase in fleet — active fleet count 9 months from now than we have today. And that might be my guess. That’s not insignificant for what it would do for market conditions.

Operator: The next question is from Derek Podhaizer with Barclays.

Derek Podhaizer: I just want to go back to Scott’s question at the top of the call. Diesel CNG spreads are tightening out there. We talked about Tier 2 diesel pricing coming under pressure, assuming that’s going to weigh on your dual fuel at first. Is that a valid assessment? And then maybe as the goal of investing in LPI to drive integration through CNG, is that a way to help protect pure frac pricing along with the rest of your integration strategy? Maybe just some comments around there, please?

Michael Stock: Right. So if I take that one, I’ll take this the last half first. Yes. I mean, our integration, our sort of vertical integration investment strategy is definitely about driving higher returns on our invested capital base, right? We’re taking the intelligence and innovation of all the people in our company and we’re focusing on them on how to make things, how to get the barrel of oil up to the surface at a lower cost at a higher profitability for Liberty, right? So that’s key. That’s key in everything we do. So that is that focus, that really makes a difference, right? Yes, does the ability to run the CNG business. Yes, one of the things we saw was that we were not running maximum substitution because of the ineffectiveness of a CNG and natural gas supply system.

That was a key limited, right? And as you move to 100% natural gas engines, that become major limited because gone is the additional cost of running excess diesel from a dual fuel equipment, you’ve got downtime if you don’t have debt, right? So that was key for the initial part of the investment in LPI, right? I was really making sure that we drive that efficiency. I mean, I think that’s a key thing there on how we are sort of managing to keep up in a softer market when we’ve got about a 20% decline in activity demand over a 2-year period, Liberty is basically flat and has the strong returns, the continued strong returns we have is because we deliver more value every day to our clients. And I think everything we do is focused around managing that and improving that.

Now as Chris says, as things tighten up as they will. I mean, eventually, diesel it’s a cyclical market, right? We’re in a lowest point at the moment. Things will tighten up. You will see the sort of forcing function effect of all that investment in vertical integration will also, you should see that improve the bottom line faster as we go forward as the market tightens, right? These are long-term investments. So I think that’s key there, Derek. And I may have missed the first part of Scott’s question there but I got on a roll, so.

Derek Podhaizer: Just comments around Tier 2 pricing, pressuring, dual fuel pricing given the spread tightening between diesel and CNG and then with the RFP season coming up and just threat of reopening and seeing some pricing pressure there?

Michael Stock: That’s differently as you’re seeing sort of there’s more and more equipment becoming dual fuel. And then we’ve got a large amount of attrition in the older equipment. As we’ve talked about, there is a valiant of equipment that was built probably in 2013 to 2014, 2012 to 2014 area, that really is getting to the end of life for the industry. So therefore, as Chris said, I think attrition is actually faster than what we’re seeing. I think what we’re seeing is we’re seeing people pump at higher rates. And more complexity which Ron can talk about and with the larger fleets. And so that is key is that we’re using more horsepower to also achieve and offset some degradation in rock. Ron, do you want to add some comments to that?

Ron Gusek: Yes. I’d add a couple of things there. First of all, I think important to remember that just because you put a dual fuel fleet out there, that doesn’t mean you get to 75% substitution automatically. We’ve talked a lot about today the progress we’ve made in substitution levels. And that’s due to an immense amount of focus internally in the organization, again, around delivering premier performance, regardless of what that is, regardless of whether it’s number of hours pumped in the field or the supply chain or in this case, the amount of fuel that we substitute. We’ve worked hard to arm our team with a level of information they haven’t had before with visibility into the operating performance of the assets we put out there.

And then, of course, with LPI to backstop that and whatnot. And so I would argue that even amongst dual fuel fleets, a dual fuel fleet is not a dual fuel fleet, it’s not a dual fuel fleet. And so I think we will continue to command premium as a result of our operational performance, not just from a high-level efficiency standpoint but even in terms of how we operate assets like a Tier 4 DGB pump. And then, yes, layering on top of that, the complexity, of course. We continue to see added complexity in the completions. You’ve seen what started out of zipper frac then simul-frac,” “trimul-frac now we’re on our way to quad-frac. We continue to work in more and more challenging reservoirs. And we’re, of course, continually focused on maximizing productivity per lateral foot.

And so you lay your all of those things on top of there. And I think we continue to deliver a package that will remain the premier choice amongst our E&P partners and as a result minimize that impact from the diesel retirement and the pricing pressure there.

Derek Podhaizer: Got it. Next question is maybe just more color on what’s driving there — to you to reach the high end of the CapEx range. I know last call; you guys were holding out maybe some growth opportunity in the back half of the year from privates. Obviously, we’re not seeing that. So I would assume you’d have some softening of CapEx just with overall activity. Are you reallocating some CapEx dollars into growth projects, specifically LPI or maybe your upgrade program from Tier 4 to Tier 4 dual fuel or Tier 2 to Tier 2 dual fuel. Just some more comments on what’s driving you up to the higher end of that CapEx range now.

Michael Stock: It’s really the timing. I mean, we’ve got a few additional growth projects that we’re investing in, things like building the constructing facilities for the growth. But yes, really, I mean, the slightly softer activity of this year doesn’t really affect our CapEx program, right? We’re investing, as Chris said, for the next 5, 10 years. That’s what we’re building equipment for. It’s a long life. It is not necessarily, unless you get a shock like COVID, or the OPEC warn on shale. It’s not necessarily affected in the short-term. it really takes into account our long-term view of our capital return opportunities. And I would say, generally, the fact that we continue to be at about 50% higher than the S&P 500. I think we are continuing to make great returns for our investors. And obviously, we can’t reinvest all of our capital because we have a very, very, very high bar for capital returns and everything below that, we are returning to shareholders.

Operator: The next question is from Neil Mehta with Goldman Sachs.

Neil Mehta: The first question is it’s always hard for us to get visibility on DUC trends because the data is so noisy. So Chris’ team would love your perspective on what you’re seeing in terms of drilled and uncompleted wells out in the field any regional color? And how does that feed into your view of pressure pumping utilization moving into 2025?

Chris Wright: Yes, Neil, I think it is hard to see exactly that data. My personal view is the DUC story has generally been overinflated. During COVID, there was a huge build-up DUCs during the OPEC frac shale. We had some big DUCs. We’ve had some major change priorities in basin. So there’s been like episodes where DUCs were meaningful. I think today and most of the time, DUCs is really just inventory of wells in progress. They’re not in the cabinet waiting for a later date. But when you drill large pads and they take a long time and the way they’re counted, a lot of DUCs are — most of DUCs are just wells in progress. There’s exceptions to that today for sure, in gas basins because of pricing is there. But — I — we don’t — so there’s a little bit of a DUC build in gas but we don’t view that as a big driver of future frac activity or optimism.

Neil Mehta: And then just a follow-up on capital allocation. You guys have done a terrific job returning capital to shareholders. The stock still trades at a big discount relative to other things in energy. So just your perspective, even if we go into a softer environment than maybe some folks would have anticipated in the back half of the year, do you still feel your — that you’re well positioned to return capital in the form of buybacks to shareholders and while we’re on the topic of capital allocation, do you see yourself participating in consolidation? Or do you continue to think buying back your stock as the best use of the incremental dollar?

Chris Wright: Right now, the dominant use of that has been buybacks. That’s not likely to change. We look at everything from consolidation. Certainly, you think of the gas market struggling right now. If there are opportunities that present themselves with the unique value or unique additive, we’ll move on that. Sometimes they’re small and sometimes they’re bigger. But we can’t count on that; we’re always looking. But — acquisitions have not been a big part of our past and they’re likely not going to be a big part of our future. There won’t be nothing but it’s got to be pretty compelling. We’re very much at grow organically develop internally. So we look at things and if things are unique, we’ll do them. But no buybacks, if I look out over the next 3 to 5 years, yes, buybacks are likely going to be a huge use of our free cash flow.

At the value we have for the stock, treat at a single-digit price-to-earnings ratio with, as Michael said, 50% higher than the S&P 500. Long-term, cash return on capital invested, it’s very attractive. So I think you will see a continued meaningful reduction in the outstanding number of shares in Liberty over the coming years and coming quarters.

Operator: The next question is from Tom Curran with Seaport Research Partners.

Tom Curran: On the natural gas side of the market, how developed is your visibility on this trajectory of incremental structural demand comprised of new LNG export trains and data center capacity growth. Are you at a point where you can look to say, mid 2026 or early 2027, translate that guest demand path into a specific number of frac spreads and then try to estimate a rough range of the additional spreads that just this new secular gas pull should require?

Chris Wright: We have done some of that but there’s so much range. And you can look at the LNG exports and maybe be a little more quantitative there because we know the projects with FID, we know the projects under construction, electricity is the bigger wildcard. There’s just such a wide range of what that could be and a lot of it is going to be availability. We’ve just had 10-plus years, I think, a very poor decision-making around the United States electricity grid. And as Germany and the U.K. have demonstrated, if you make electricity, expensive and unreliable people will consume less of it. So I think the biggest holdback in draw for gas in our electricity grid is going to be prices and reliability of our electricity. I frankly think it’s embarrassing how long electricity was down in Houston for a pretty moderate storm, 100 years ago, we had storms massively larger than that.

And obviously, we didn’t have a sophisticated of a grid. But I think — so the short answer is we talked about it internally. We have ranges of it. It’s not trivial. It’s not game changing either the amount of fleets that will come. But we don’t give the numbers because there’s just too many assumptions in which trajectory might unfold. We do say and that the outlook is pretty positive for U.S. natural gas demand from both those sources. LNG, electricity demand, I think we’re going to see some more reshoring of manufacturing in the U.S. and I think we’re going to see over the next several years, more of that in Mexico as well. And so I think that connection of U.S. gas going to Mexico is going to be increasingly important as well. So the macro is positive.

But this is probably a discussion over dinner or a beer. We could sketch out the range of this many more fleets to that many more fleets. But I’m going to refrain from giving any numbers right now but I like you’re thinking.

Tom Curran: Sounds good. And we’ll let Ron pick up the tab for those beers. Turning to LPI; it sounds as if a portion of your CNG sales in June were to your customer base for its drilling rigs. Were those land rigs CNG deliveries, a separate third-party revenue transact or part of a bundled contract? My impression has been that Liberty’s own fleet needs, we’re likely to command the bulk of LPI’s capacity this year. So I’m just taking a clarification and maybe an update on what the outlook is for LPIs external third-party business trajectory?

Michael Stock: Yes. So the vast, vast majority of our gas deliveries are for our fleets. We’ve been delivering for drilling rigs since the Siren acquisition, right? So for key clients in basins in both the Permian and the DJ Basin. So delivering of — gas usage for drilling rig is much, much lower than it is for refractory [ph] — much, much, much lower. But again, it’s you’re still delivering CNG with the same equipment. So it’s just part of the business. It’s all about supporting the overall health of the industry.

Chris Wright: Yes. It’s a partnership thing. You’ve got customers that are running rigs out of gas and Liberty is the highest cost supplier there, they want to use it. So yes, it’s not a huge part of our business but it is a nice part of our partnership.

Tom Curran: Got it. And I’ll just squeeze one more in here. Ron, I’m sorry if I missed this but did you provide an update on how many active digi spreads you expect to have deployed exiting the year?

Ron Gusek: No change in our plans there at all, Tom. We’re still on track to have operating by the start of next year, 10 next-generation fleet. So no change in our outlook for that.

Operator: The next question is from Keith MacKey with RBC Capital Markets.

Keith MacKey: Certainly, vertical integration has been a differentiator for the business and we’ve talked about it on the call so far. But just curious if you can give us a little bit more color or even potentially quantify, how far along do you think you are in this process? Is there a lot more benefit to be realized from adding service lines or growing existing service lines that you’ve got. I know LPI is certainly a big part of that. But just some general color on how much of the value chain you think you’ve actually been able to capture to date and in frac and how much more you think there is to go?

Chris Wright: Look, I’d say we have vertical integration in most of the big items that matter. So yes, I wouldn’t say there’s a huge amount there. The biggest focus at Liberty is just how do we get better? As we always say, we didn’t do the vertical integration, so we could like add that business line profitability on. We do add that business line profitability on but most of them aren’t huge, we’re doing and really just to make frac the core business better. More reliable, safer, more efficient, a better experience and better value add for our customers; that’s what’s driving it. As Michael said, look, the net result is we’re capturing more of this profitability but really, we look at it as that whole piece. So we’ll continue to develop technologies.

We’ll continue to do things to make our frac offering meaningfully better than all of our competitors. That was our goal from day one. And it will never stop. But vertical integration, I would say the bigger prospect for us, growth in the next 5 or 10 years is going to be taking the tools and technologies that we’ve developed. For example, remote power generation with natural gas and a virtual pipeline to supply in. That’s a way bigger growth in Liberty’s business over the next 5 years than — then a likely expanding of our vertical integration but it’s not likely to be, I would say, meaningful for the size of our business. But more important is, again, ultimately going to electricity business and just a maniacal focus on getting better, getting better, getting better.

That’s the big story.

Keith MacKey: Okay. Very good. And you have investments in businesses outside of frac, I know you talked about Oklo and Tamboran as the impact on earnings per share. You’ve also got a few others. Can you just talk about maybe the 1 or 2 most important insights or lessons you learned from having investment in energy businesses outside of frac?

Chris Wright: Yes. Look, as career energy nerves, we get asked to invest or ask to advise other entrepreneurial energy companies a lot. We get pitch on a million things. But I think maybe a little bit of our differential advantage there is what — we just look at if it’s operated well, where could this business be? Most of the new venture energy business is in our opinion, even if everything went right, like they don’t have a prospect to be a meaningful positive addition to the global energy system which means there are bet on subsidies. And we’re not takers of those bets. We’re not believers in that and we just — we don’t want to bet on the government. We want to bet only on these fundamental these technologies or things that are doing could be a great player in a future energy system.

So we’ve been disciplined. We’ve only made a few of them — and we’ve generally only made them where we can bring something to the table. Oklo is a great example. It’s just like the right nuclear technology, the right business model; the technology is fantastic. But bringing energy to a marketplace and putting all those packages together and then getting the right commercial terms, man, we’ve been doing that for our whole careers. So I think we add some real value to a thing that’s just an awesome kernel. And Tamboran, of course, is even simpler to look at. It’s — man, I remember the excitement of the Barnett Shale 25 years ago, like the progress every year. My God, we’re going to figure this out. Look, we didn’t appreciate that how big it would be but just to have an awesome resource in place in a geographically desirable location like that’s a solvable challenge that could have a big impact on Australia, not for domestic consumption and for exports.

And I think Liberty could be very helpful in making that successful. And I think the upside for us is quite large there. We view this as a very asymmetrical bet, very little downside and a lot of upside.

Operator: I will now turn it back to Chris for closing remarks.

Chris Wright: All right, everyone, feel free to drop off if you want but I’m going to talk a little bit more about energy. With the benefit of 2023 energy data which is now available, thanks to the Energy Institute’s recent publication of the statistical review of World Energy, I want to take a moment as we close to provide an update on the so-called energy transition. The Energy Institute’s work to quantify global primary energy is quite valuable to all energy nerds like us at Liberty. However, we made 2 important adjustments to the Energy Institute’s number within our bettering human lives report. First, EI does not account for developing country use of traditional biomass in their primary energy numbers. This traditional biomass energy is the source of the world’s largest energy problem.

Hence, we believe it is critical to always include this in all the energy reporting. Traditional biomass serves as a cooking and heating fuel for 2.3 billion of our fellow humans, a suffering grinding poverty. Our Bettering Human Lives Foundation works to help these 2.3 billion people transition to clean cooking fuels, to allow longer, healthier, more opportunity-rich lives. That is a real energy transition that we need to hasten as quickly as possible. You can’t eradicate what you don’t attempt to measure. The EI employs an input equivalent methodology that grossly inflates the primary energy from electricity produced by wind, solar, hydro and nuclear. They multiply it by 2.4x in their conversion of terawatt hours to exajoules. We reversed this adjustment and simply convert reported terawatt hours to energy equivalent exajoules which is the actual energy delivered to and consumed by consumers.

We discussed this more in the bettering human lives report. In our — but for us it’s critical to be honest in the reporting on energy, on climate change and human progress. Incidentally, the U.S. Energy Information Agency recently reversed its long-standing practice of using an input equivalent methodology and is now in step with us in its reporting. Nice to see the U.S. EIA make this change. So with those adjustments, corrections, we find that over the past 50 years, global primary energy consumption has more than doubled. It’s up 126% and we’ve seen a 1.6% compound annual growth rate in energy consumption over the last 50 years. Energy additions from hydrocarbons over that 50 years are nearly 6x higher than all other energy sources combined.

Hydrocarbon share of primary energy was 85% 50 years ago and it’s 85% today. Since the start of this century, global primary energy consumption is up nearly 50% or as slightly higher 1.7% compound annual growth rate. Thanks to the American shale revolution, energy additions from fossil fuels are over 7x greater than all other energy sources combined during the last 24 years. Hydrocarbon share of primary energy, their share of primary energy increased by 1.4% back up to the 85% of 50 years ago. We look at just the last year, global primary energy consumption increased by 1.6%, in line with trends. Energy additions from hydrocarbons were nearly 4x higher than all other energy source combined. Oil was the largest addition by source and coal was second over just the last year.

Natural gas has been the biggest over the last decade or so. Hydrocarbons remain at 85% of primary energy, wind and solar combined for a share of 2.6% of primary energy last year. I will close with a plea yet again to all my colleagues in the industry, particularly the analysts and bankers to stop using the deceptive and destructive term energy transition. First, because it is simply wrong. The share of hydrocarbons in the global energy supply stack has not shrunk in 50 years. In fact, hydrocarbons have actually grown their market share over the last 24 years. Yet the incessant repeating of the simply false term energy transition contributes to a serious misunderstanding of the global energy system with destructive consequences, including damaging political energy policies, seriously misinforming kids in our schools and most relevant for today’s audience, it has perhaps driven down investor valuation of hydrocarbon companies due to the impression that our industry is soon fading away, even though the numbers do not support this view.

Energy is far too important to get wrong. 7 billion people are striving to achieve highly energized lives, just like us in the lucky 1 billion. Let’s not use deceptively destructive language that impedes them realizing their dreams of affordable, reliable energy access. We should all strive to speak accurately and honestly. We need to stop using the false term energy transition and instead use energy addition. We would also be better served not to use the deceptive marketing terms, renewable and clean energy as they’re also not supported by facts. How about new energies or alternative energies, the term that we used before we got off-track. Have a great day everyone.

Operator: The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.