Liberty Energy Inc. Q3 FY2020 Earnings Call

Good morning, and welcome to the Liberty Oilfield Services Third Quarter 2020 Earnings Conference Call. After today's presentation, there will be an opportunity to ask questions. Please note that this event is being recorded. 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 risks and uncertainties, which are detailed in the company's 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, and pretax return on capital employed, are not substitutes for GAAP measures and may not be compared to similar measures of other companies. A reconciliation of net income to EBITDA and adjusted EBITDA and the calculation of pretax return on capital employed, as discussed on this call, are presented in the company's earnings release available on its website. I would now like to turn the conference over to Liberty's CEO, Chris Wright. Please go ahead.

Good morning, everyone. In the midst of a global pandemic and an oil and gas industry downturn, our third quarter results demonstrated the resilience of our business. The Liberty family came together to work through an extraordinarily difficult time for the industry by applying our core principles to meet near-term challenges, working hand-in-hand with our customers. Our customers have been as challenged by current conditions as we have been. We are in this battle together. Just as with our personal lives, relationships are strengthened or broken during trying times. Liberty is growing and strengthening our relationships with our customers and our Q3 results reflect that. Completions activity is modestly ahead of the pace we expected earlier this year at the outset of the downturn, and we continue to grow market share percentage of business with our top-tier customers. The third quarter also marked an entry into our first major gas basin, the Haynesville Shale, with an existing customer. The Haynesville is a world-class gas resource, geographically advantaged, being developed by a crew of strong operators. We are excited to plant our flag in the Haynesville. Our third quarter adjusted EBITDA, excluding noncash items, was $1 million, a $10 million improvement from the second quarter as operators restarted frac activity following an abrupt halt in the oily basins during the second quarter. Cash and cash equivalents were $85 million at the end of the third quarter. And total liquidity, including availability under our credit facility, was $154 million as of the September 30 borrowing base. Because of the severity of this downturn, I want to remind investors of how incredibly hard the team has worked to navigate all the challenges while keeping our people safe and our customers served in the top-tier fashion that they are accustomed to. I'm pleased with our team's solid execution that has translated into the significant improvement in our Q3 results, albeit with much room for further improvement in the coming quarters. All these efforts and decisions have been critical for Liberty's future. Not all of them have been easy. Michael will share our full financial results shortly. Despite near-term macro volatility, we never take our eyes off the long-term goal of building a competitively advantaged leader in North American frac. Our strategic goals have always been centered on building a business for longevity and returns through cycles, which requires a strong balance sheet and solid liquidity. We are pleased with the positive reception that the OneStim deal has received from our partners, customers, suppliers, and investors. We are excited by the conversations and integration preparation work we've done so far with our colleagues at OneStim. Let me briefly discuss OneStim. Bringing these two businesses together has energized our team. Our integration work is still in its early stages. We are immersed in discussions on people, technology, assets, strategy, and our future technology alliance framework. This is a huge effort with huge opportunities. Things are progressing quite well. We are pleased with how complementary our engineering databases and the innovative technology solutions are for completions designs, and we're excited by the future opportunity to deploy an even better service offering. Suffice it to say that there are simply tremendous opportunities for Liberty to supercharge our technology platform. We will roll out more details on specific initiatives in the near future. Let me say again, technology was the major driver behind this transaction. We are also excited by the pump down perforating wireline business and the sand mines. It's simply too early to comment on any more specifics at this point. We expect to close the transaction towards the end of the fourth quarter. We have already received antitrust clearance. Frac activity rebound has continued at a modest pace, likely supplemented by Liberty's gains in market share. We exited the third quarter at a much higher level of activity than the quarter began. We see activity now leveling off until the seasonal decline towards the end of Q4, which we expect to be more modest this year. For the fourth quarter, we are now anticipating average active frac fleets, excluding the acquisition of OneStim, will increase by greater than 20% from the third quarter. I must recognize again and give thanks for the great sacrifices made by all of those in the Liberty family. I'm pleased to share that we no longer have any employees on furlough. While we are on the road to recovery, it will take time. Oil prices are bouncing around $40, an improvement from the spring but still too low for a healthy industry. Natural gas prices are at a somewhat better place today than oil prices. The U.S. onshore rig count bottomed about 3 months after the active spread count bottomed and has also been modestly improving with six consecutive weeks of growth. Current industry activity levels, likely around 130 active frac fleets, are well below the level of activity needed to hold U.S. oil and gas production flat. Hence, we expect to see further increases in activity levels next year. Liberty is responding to the reality that we have today and building our competitive advantages for however the future unfolds. Customer relationships are central to this. Last quarter, we discussed that our engineering prowess and completion designs were catalyzing more conversations with customers. Crisis catalyzes change. Those discussions have accelerated even further. Customers are looking to Liberty for new ideas and greater innovation to lower the cost of producing a barrel of oil. ESG is also a growing part of our customer dialogues. We are working hard to release our first ESG report for the end of the year. We are anxious to bring a fresh, candid perspective to this growing issue on our industry and our times. These are busy and exciting days for the Liberty family. I will now turn the call over to Michael.

Good morning, everyone. It has been a challenging six months for our industry. And in the second quarter, we transitioned the business to align our cost structure with our dedicated customers' projected activity levels and our financial results reflect these changes. During the third quarter, we were pleased to see month-to-month improvement in the frac activity from trough levels in the middle of the second quarter. These partnerships with our well-capitalized dedicated customers allowed us to achieve results slightly ahead of our projected pace during the period. In the fourth quarter, we are now expecting greater than 20% sequential growth in average active fleets, which is the top end or higher than our prior guidance of 10 to 12 fleets. For the third quarter 2020, revenue increased 67% to $147 million from $88 million in the second quarter, reflecting a steady return of activity as the commodity prices backdrop stabilized, albeit at low levels. And net loss after tax totaled $49 million in the third quarter, improving from a $66 million loss in the second quarter. Fully diluted net loss per share was $0.41 in the third quarter, ahead of the fully diluted net loss per share of $0.55 reported in the second quarter. Severance and related costs were $1 million during the quarter, and fleet start-up costs included in the cost of sales was $6 million for the quarter. Third quarter adjusted EBITDA improved to a loss of $3 million in the third quarter from a cyclical low of $13 million in the second quarter. Third quarter adjusted EBITDA was a positive $1 million after excluding noncash items of $4 million. Results were driven by a modest return in frac activity in the third quarter, following the second quarter production shut-ins and curtailment of completions by operators in the oil basins. General and administrative expense totaled $19 million, including $1.5 million of one-time transaction costs related to the OneStim acquisition in the third quarter, a modest 4% increase from the second quarter as our cost-saving measures taken early in the second quarter continue to aid overall results. This modest increase in general and administrative expenses was primarily due to the timing of certain corporate costs in the third quarter as well as higher activity, driving an increase in personnel cost as employees returned from furlough. We anticipate a modest uptick in general and administrative expenses during the fourth quarter on a full quarter of no furloughed employees. Net interest expense and associated fees totaled $3.6 million, and we recorded an income tax benefit of $10 million for the quarter. We ended the quarter with a strong liquidity position of $154 million, including a cash balance of $85 million and no borrowings drawn on our ABL facility. Capital expenditures were $12 million for the quarter and $58 million for the year, and we continue to expect capital expenditures in 2020 to be in the $70 million to $90 million range. Fourth quarter capital expenditures are expected to primarily include maintenance CapEx on increased working fleets, investment in next-generation fleets, and other items. The exceptional circumstances of this historic downturn in oil and gas have been bittersweet. We acted swiftly when circumstances were highly volatile, reducing staff, conserving cash, managing our liquidity, and maintaining a strong balance sheet. Our core principles allowed us to navigate a very challenging market. Equally importantly, it also allowed us to take advantage of opportunities that will make us stronger as the cycle improves. The acquisition of OneStim is a prime example of executing for the future. We believe OneStim will serve as a catalyst to advance our goals in generating superior returns as we have in years past. As Chris discussed, we expect to close our acquisition of Schlumberger's frac business late in the fourth quarter and our integration efforts remain on track. We have long been focused on investing in the future with a sustained focus on technology innovation. For this deal, we believe we can deliver even greater value to our shareholders through a strong investable platform. And with that, I will now turn the call back to Chris before we open for Q&A.

While the timing of full recovery in global oil demand remains uncertain, the last several months have shown a dramatic rebound from the lows in April and May. However, a resurgence in COVID cases now threatens the future pace of recovery in oil demand. Against this backdrop, there has been a concerted effort across the industry to cut costs and drive efficiency improvements. As part of that effort, we've seen several significant consolidations announced among E&P operators, including Chevron-Noble, Conoco-Concho, Devon-WPX, and Pioneer-Parsley in the oily basins, and we expect more to come. These trends will likely persist into 2021 across the oil and gas industry. We expect that best-in-class operators and service companies of larger scale will emerge on the other side of the downturn. A full-fledged recovery or return to normal depends on a rebound in global economic activity. This will take time. World Health Organization officials expect a doubling of the global poverty rate, a tragic and dramatic reversal from the plummeting of world poverty over the previous decades. One of the greatest drivers of demand growth for oil is people's lives getting better around the world, whether that is rising out of poverty, entering the middle class or moving up to a more affluent middle class life. All of these improvements demand more oil and gas. The simply tremendous economic progress of the last century has been abruptly interrupted. We long to see this trend reverse again, both for what it means to our industry and more importantly, for what it means for the well-being of the world's people. Thank you for joining us today. We look forward to fielding any questions that you may have.

And our first question today will come from Blake Gendron with Wolfe Research.

I appreciate the commentary there about the oil and gas impact globally. I know it's still early days and you're still going through your review with the OneStim technology and equipment. It's pretty easy to see what Liberty can do with scale and in terms of driving efficiency and throughput, that definitely follows through to the EBITDA line. In terms of free cash conversion, it would seem you have an opportunity to cannibalize some equipment. So my question is, as you look at the equipment now and maybe it varies a little bit by basin, does the equipment on the OneStim side match up well with Liberty's equipment? And what do you think the extent of these cannibalization savings on maintenance CapEx could be both next year and moving forward?

Thanks, Blake. And I'll take a little bit of that. It's Michael. Yes, the equipment matches up very well, really. They sort of run a very similar drive train to what we have. One of the key decision points that I think Ron and the team are looking at is, as far as when we're looking at control systems, just one of the things we have to standardize across the system. But the equipment itself is in great shape. And we'll have, I think, about 500 green tagged pumps. So we'll have a lot of equipment that's in tip-top running order. We will have a significant amount that will be available for reducing capitalized maintenance and costs going forward. Still in the stages of looking at that. As you can imagine, there's a lot of equipment to look at. But we've announced, I think that's probably going to be somewhere in the range of $50 million to $100 million reduction in spend over the next three years. I would guess that is probably a little bit of a bell curve, a little bit slower in 2021 and then a smaller amount out in the third year. Probably the highest amount of that savings comes at the back end of 2021 and through sort of 2022.

Understood. And what piqued our interest, obviously, was the Haynesville entry with an existing customer. OneStim, in our view, was pretty impactful in the Haynesville region. We just don't hear a lot about the nature of the work with respect to maybe pad configuration and what the wells are actually like just because it's fragmented from an E&P standpoint, and also, you have some private frac companies that are operating there as opposed to large public ones like yourself. I'm wondering if you can maybe characterize the nature of the work in the Haynesville with respect to maybe the efficiency and throughput upside. Maybe comparing a Haynesville pad to a Permian pad would help us illustratively understand the opportunity there.

Yes. So this is Chris. The Haynesville is deep and highly overpressured, which contributes to the huge size of the resource. But it means it's a high-pressure basin. So which means pumping above 10,000 psi. So it's high pressure. The reservoir is thick, so the pounds per foot or frac intensity is high in the Haynesville. And their EURs and recoveries are highly dependent upon frac intensity. So it's significant-sized pads. And that each well, I would say, on average frac intensity is higher than in the Permian. And it's high pressure, so it's more like Delaware than Midland Basin. But yes, there are sizable private operators there as well as the publics. But the resource base and the outlook for it going forward is tremendous. We've been looking at Haynesville for a while. We like the outlook there. I would say I'm super proud of our team to arrive in a new basin without a base there and to perform very strongly right out of the gate. So a customer we arrived with there, we will be very busy with next year. And as you said, yes, OneStim has a significant presence there, and it's been doing some great work, and they have a facility. So yes, I see Haynesville as a significant basin for us going on for a long, long time.

And our next question will come from Chase Mulvehill with Bank of America.

So I guess I want to dig in a little bit on kind of 3Q. The sequential revenue improvement lagged your increase in your average fleet count. So could you maybe talk about how much of that is utilization versus kind of mix?

There's two big factors. Number one, our percent of self-sourced profit pumped in Q3 was sort of inordinately high. So that in itself means for the same amount of frac activity, revenues are lower. The other is you have work, and in Q2, at the beginning of Q2, you've got a lot of work going on that was a continuation of work from Q1. So it's a better pricing environment, and all fleets are running on all cylinders and smoothly operating on day one of the quarter. Where here, you've got launching of new fleets, working out kinks and getting things back up again. And of course, you've likely got a lower average pricing in Q3 than you do in Q2, thinking of the Q2 work as mostly at the beginning of Q2 as you're going into shutdown.

Okay. Perfect. And then if we can kind of carry this question into Q4. Given that backdrop, obviously, you've guided your 4Q average fleet count up more than 20%. How should we think about the moving pieces between mix and utilization as we kind of go into 4Q relative to 3Q?

We go into 4Q with a strong activity level. So the fleets are running at high throughput going into Q1, so you'll likely see a more positive revenue per fleet likely in that setting.

Okay. And last one, real quick, on frac pricing. Are you still seeing pressure out there today on the pricing side? Or is it actually at the bottom?

Yes. I would say we're at a bottom. But my first reaction when you say frac pricing is it's terrible. Just an industry right now where there's a lot of excess capacity, it's almost a necessary thing. It's what is pushing capacity out of the marketplace. So pricing is very tough right now. But yes, it's not going down. It's just, yes, it's at a very low bottom.

And our next question will come from Marc Bianchi with Cowen.

I'm curious on the kind of activity progression here. I mean I know you guys have guided to the over 20% here for the fourth quarter and kind of made the comments about what's sort of needed from a market perspective to sort of hold production flat. But my sense is most of those sort of maintenance expectations were kind of based on $35 oil and the commodity prices drifting lower here. So I'm just kind of curious, how do you see that commodity price weakness playing into sort of the broader market activity as we head into '21? And how does that affect your business and what you've sort of put forth here for fourth quarter?

Yes. I would say that lower commodity prices will definitely affect activity. If we had looked at this three or four months ago, the general expectation was that U.S. production would remain steady at the December exit rate. However, given the current tone and the concerns about declining oil prices, it seems likely that it will take longer than anticipated, possibly even beyond next year, before we reach activity levels that stabilize U.S. production. Regardless, from where we are today, I still anticipate that we will see higher average activity levels next year compared to the current levels. The extent of that increase will likely depend on oil prices. If oil prices are in the mid-40s, that presents one scenario. Conversely, if oil prices remain in the high 30s, or around the levels we are seeing today, we can expect increased activity, but with a much smaller rise than the current situation.

Okay. And then one, just in terms of the kind of the margin leverage here. In the third quarter, I know there was some restoration of furloughed workers that may have weighed on sort of your margin leverage. If I kind of look at the EBITDA improved $10 million, which works out to a mid-teens or 10% to 15% incremental. What should we be thinking in terms of your margin leverage or operating leverage in the fourth quarter just in light of this sort of 20-plus percent activity increase?

Yes. It should be a little bit stronger in the fourth quarter than we came into in the third quarter as we were relatively flat. Everybody is being brought back from furloughs, going to be brought back from furlough. Obviously, we're also dealing with the OneStim acquisition and probably going to find that we're going to run a little heavy on some of the costs and some of the transaction costs into Q4 as we go.

So Michael, to follow up on that, if we consider what a typical incremental gain for the business would be without the unusual factors, we can then discuss what to account for based on the points you mentioned.

I don’t think we should go into that right now. It’s too unpredictable at this stage. As we emerge from this unusual low point, discussing typical incremental changes at this moment could create more confusion than clarification.

And our next question will come from David Anderson with Barclays.

So Chris, I want to ask you a bit more about the E&P consolidation you talked about in your prepared remarks. It seems to me it's a bit of another reason for investors, I guess, to hit on the oil space. But on the surface, it seems that 1 plus 1 equals something less than 2 when it comes to putting a couple of these programs together. What's the counter to this? Can you just kind of talk about how you think about this? Does it kind of ultimately become sort of a frac-off between your competitors? Just sort of maybe talk about how you see those dynamics playing out, because there's so many of them, and I guess in the next 12 months, we'll find out how that all shakes out.

Yes, they will all be different. There are both negatives and positives to consider. The negative, as you mentioned, is that when two companies merge, they often reduce costs and capital expenditures. In general, the combined value will likely be less than the sum of the parts. This situation focuses on reducing capital expenditures while increasing efficiency, which is generally disadvantageous for the oilfield service sector. However, the positive aspect is that we will see larger and more robust exploration and production companies emerge. These companies are likely to collaborate with bigger, technologically advanced service providers, which can create a competitive advantage for a business like Liberty.

And I think just a follow-on from that, I think, in the long term, while it does, it makes the U.S. oil and gas sector more competitive at a lower price, and so therefore, will drive more development in the Lower 48 in Canada from larger companies who have got access to capital to survive and sort of what I think is to allow for lower oil prices. So therefore, should actually advantage us over the long term, even though you're right, we may have some hiccups over the next six months.

Right. Yes. No, that seems pretty clear. There clearly are opportunities for you as well. So a separate question and also kind of a bigger picture question. I think we can safely say that Liberty manages more of the supply chain, I mean, sand, chemicals, water, than any of your competitors. It's something you feel is an advantage of winning work. Taking all that into account, I'm just wondering where do you see the potential for a potential step change in efficiencies here? One operator kind of complained to us that 70% of the cost of profit is on trucking alone. I don't know if that's the same for all your operations. But it's just sort of generally speaking. I'm wondering if supply chain efficiency is a problem that you're trying to solve. And I'd also be curious if you have a digital overlay over these operations, whether it's internal or third-party or just kind of where you stand on kind of software as helping those programs out?

Yes. This is Ron. I think we see that ultimately as a hybrid model. Of course, there are opportunities where a piece of software is going to make a better decision than a person. And I think you see that opportunity, particularly in the last mile piece of things. So to your point around trucking being 70% of the cost of sand, that's certainly true in some places. That's not true every place we do business. But if you were talking about a particular basin, maybe the Permian, for example, that could absolutely be the case. And so yes, as you think about that last mile piece, the opportunity to lower trucking cost comes in effective utilization of those trucking assets, enabling those folks who own those trucks to make more turns during the time they're allowed to be out driving. And so that requires an efficiency or an optimization exercise. And the computer is very, very good. Artificial intelligence will be able to move the needle to some degree there. But I think we feel, at Liberty, there's a limit to what a piece of software can do in terms of replacing a human. We place a lot of value on the relationship we have with our suppliers and what that means when times get challenging. I think there's no replacement for being able to pick up the phone, have a conversation with somebody you know and have a relationship with to work through a challenging supply issue, whatever that might look like. And so I think we see opportunity there to improve efficiency, but I think it's going to be a mix of both software and the ongoing relationships we pride ourselves on with our customers and suppliers.

So Ron, related to that, I'm curious if you're in a position now where you can say, hey, we can provide this last mile x percent cheaper than our competitors, is that a selling point? Is it like a 10%, 20%, 30% number? I'm just kind of curious how you think about that in terms of a competitive advantage.

Yes. I don't know that I could quantify exactly what that is, but it's meaningful. There's no question. I think we are confident we can convey to our customers an advantaged supply chain that looks differential to everybody else's, and I think that carries a huge amount of weight. And I think that's the reason you've seen us generally be on the lower end in terms of self-sourced profit side. I think our customers have confidence in our ability to deliver to them a competitive supply chain that is a function of scale we have, that is a function of the relationships we have, that is a function of the ability and focus we have on that, and it's important in our world.

That's one of the things that we're getting. One of the things we really love about the OneStim deal is we are getting some software and the work they've been doing on some software related around that, that we'll be able to sort of leverage across the new scale of the company in conjunction with sort of, again, as Ron would say, moving sand efficiently, and then sort of being able to stage those trucks using artificial intelligence and geo-fencing to actually manage the time between loads and sort of increase that efficiency. I think it's a key thing. They've done a lot of this thing over the last few years. We'll be able to take that investment and then commercialize it and put it out to our customers to really help them. Our larger customers are going to be our largest set of the scale of demand and help them lower their costs.

In addition to efficiency and cost, another advantage we are actively working to enhance is reliability. Disruptions can occur, such as when a mine goes down, the market is tight, or weather conditions are unfavorable. Our competitors have experienced significantly more downtime under stressful conditions. Liberty takes pride in our robust ability to maintain operations consistently across all circumstances. This reliability is recognized and valued by our customers, and we aim to further strengthen the robustness of our supply chain.

Our next question will come from Sean Meakim with JPMorgan.

So to follow-on to the decision to enter the Haynesville, Chris, you've avoided dry gas basins to date. But the move is not surprising, you're going to take on Schlumberger's fleet and their existing footprint. You always try to invest countercyclically. Could we just talk about your timing of entering dry gas markets and what that signals in terms of your outlook for gas-related activity?

You bet. The shale revolution started in the gas basins, primarily due to technical innovations in the late '90s that didn't gain much attention until the mid-2000s. It initiated there because gas molecules are smaller and can move through tiny pores in rocks and microfractures. Initially, we were uncertain about how this would translate to oil or the potential scale in the oil basins. Fortunately, that turned out not to be a limitation. However, the strong performance in gas led to a rapid increase in U.S. production, and the learning curve improved quickly. We launched Liberty as we are optimistic about the long-term future of natural gas. We anticipated a swift decline in rig and fleet counts in the major gas basins, which has indeed occurred over the last eight years, while we expected growth in the oil basins. Another significant factor is the ease of loading oil; the U.S. was a major net oil importer, which could be replaced, and oil exports are relatively straightforward. Exporting natural gas requires more effort and a larger investment cycle. Looking at the present situation, the U.S. initiated the shale revolution and became the largest importer of natural gas globally. Now we are the third-largest LNG exporter with ample growth potential and increasing pipeline capacity to Mexico. This infrastructure development has occurred, and we have witnessed declines in rig and fleet counts in the major gas basins. After several years of substantial declines, we believe we have reached a bottom. Though it may not surge dramatically from this point, I anticipate increased activity in those basins, even if they don't see much growth. During the downturn's depths, a significant portion of activity was concentrated in gas basins, reflecting different dynamics and marketplaces. We've engaged in discussions about gas for several years, with various customers expressing interest. Therefore, independent of the OneStim acquisition, we would have moved to the gas basins. As for timing, we entered the Permian at the bottom of the previous downturn, augmenting our market share in the Rockies from 5% to 25%. This was the first time in our history that we had spare capacity, allowing us to enter the Permian. Similarly, during this downturn, we saw spare capacity and felt it was an opportune moment to enter the gas basins. The third factor was having a reliable customer in mind, which made our entry timely and logical. So, I would say that even without the OneStim deal, we would be in the Haynesville today in the same capacity. We'll quickly scale from this entry point. I apologize for the lengthy answer, but I appreciate your question.

No, it's a good answer. I think that context is really helpful. And then just thinking about the digiFrac, are we still track for deployment next year? I'd be curious to understand a little bit more what the capital outlay looks like relative to a traditional diesel fleet? And just how you think about securing a firm contract before you put this type of fleet out to the market.

Yes, we are having discussions about our fleet due to its different technology and emission profile. There is considerable interest, but the market is challenging. We are planning to conduct tests and will be operating engines in the field in the coming months. Based on the timing of a suitable commercial agreement and the success of our development efforts, it is quite possible that we will sign a deal to deploy a digiFrac fleet within the next year. The timing could vary, and while we are not in a rush, what matters most is ensuring that the technology is reliable and truly innovative, and that we establish the right commercial agreements with suitable partners.

And our next question will come from Tom Curran with B. Riley FBR.

Most of my questions have been covered. So I'll turn to one of my regular topics, which is your continued involvement with the VorTeq system. Would you please update us on your initiative to deploy that technology on a live well with an existing customer before year-end? And then how does the acquisition and integration of OneStim affect your VorTeq plans, both in terms of the specific timing of this trial well and then the others that might follow, and then longer term, how you would intend to roll that technology out across the merged fleet?

Yes, Tom. We were well on our way to putting that technology out on a live well right before the world turned upside down for us, and in fact, I'd say maybe weeks away from doing so. So we're back on that path again. We're out looking for the right trial candidate to have that on, of course. We want to make sure we set ourselves up for success when we go out to do that. And so the sales team here at Liberty is working with our E&P partners to find the right candidate for that. And when we find the right opportunity, we will get that technology out in the field and get through the remainder of the testing that we would like to do there. Once we've done that, then we evaluate the commerciality of the technology and make a plan for deployment beyond that. So that's where we sit today. We don't have that date nailed down yet, but know that we're working hard to find a spot to get that out in the field again. As far as the OneStim acquisition, it didn't really change our outlook on VorTeq. Of course, we were working together with energy recovery and had been for a long, long time. That was mostly independent of the OneStim team. Of course, they had their own efforts moving forward. They're in parallel with us. I think maybe we both had a little different thought around how we were going to deploy that and how we were going to use that technology. We continue on with the plans that we had there. And once we get across the finish line and have a chance to evaluate how it performs in the field, then we make that final decision around deployment, obviously, with a little bigger footprint to consider that over now.

Just two follow-ups then. Do you still expect to have the first live well frac underway before the end of the year? And regarding your commercial evaluation, are you open to deploying it across the entire fleet if you're satisfied and it seems like the technology will meet all your requirements?

We hope to have it completed before the end of the year and are actively seeking the right well. When we find a suitable candidate, we will be ready to proceed on short notice. After completing extensive work in the yard and other tests, we are confident in integrating the technology with our standard rig setup, which won’t take much time if we can identify a candidate quickly. Our goal is to achieve this before year-end. In terms of deployment, there are specific areas where VorTeq is likely to be more effective due to the higher wear and tear on the pump's wet end, fluid ends, valves, and seats. This variance is influenced by job design, the pressures we are pumping, and the type of fluid system in use. These factors will ultimately guide our decision on where to deploy VorTeq initially when we determine that we are ready to move forward.

Our next question will come from Chris Voie with Wells Fargo.

So I think you said you expect revenue per fleet should be higher in the fourth quarter, and it sounds like pricing is not going down. So is it fair to assume that underlying GP per fleet, which I think was probably around $6 million in the third quarter, if you ignore reactivation costs. Is it fair to think that, that should be higher in the fourth quarter compared to the third quarter?

It's a lot of moving parts on that one, Chris, obviously. But yes, I mean given the small set of assumptions you just mentioned, that would be logical. But that was based on those small set assumptions. So yes. No guidance. We will not give profitability guidance, so as you know.

Sure. I'll skip my next question about fourth quarter EBITDA. Switching to pricing, is bidding still within a tight range? In previous quarters, it seemed to be mostly tight with a few exceptions. Can you describe the current pricing landscape? Clearly, there's a desire to maintain stability, as many others feel the same. Are there still some undisciplined bidders affecting the situation?

Well, I think the tight band is a reasonable characterization. But often, there are some bids that are way off that reservation, for sure. But usually, it's from players that have other limitations that make them not a great potential partner for us. So there's a lot of, I would say, in general, the crazy cheap bids, even though they may be a fair amount cheaper than everyone else, in general, they're not successful with the better companies. You're making a partnership, and there's a reason someone's doing something like that. And I think that the experience of the last six months maybe even hammered that home more to the E&Ps, that if it looks really cheap upfront, maybe there's a reason for that. The cost of partnering with the weaker players, it certainly have been made apparent in the last six or seven months.

While pricing is currently challenging, some of the less disciplined competitors have left the market or are no longer active in that area. Despite the tough pricing environment, most of the available fleets are now operational. It will be interesting to observe how pricing evolves over the next three to five months, although we don't have clear indicators of its direction. However, it stands to reason that if service companies begin hiring and staffing new fleets, they will be seeking a return on that investment. I anticipate that the majority of the industry will maintain a level of discipline.

Okay, that's helpful. And if I could just sneak one little one in here. Do you have a view on reactivation costs in the fourth quarter compared to the $6 million in the third quarter?

Yes, we should maintain a relatively stable fleet count through the fourth quarter. Therefore, I anticipate a smaller amount and fewer numbers as we move into next year. It's important to remember that we essentially halted operations in the oil basins, requiring significant efforts to restart. This process during the third quarter involved various costs and inefficiencies.

And our next question will come from John Daniel with Daniel Energy Partners.

I got dropped early on because driving around here, so I don't know if my question has already been addressed. I apologize in advance. But can you speak to what the inquiries are, bidding opportunities are, the volume, if you will, for Q1? And also address sort of what portion of your fleet today is dedicated and why you would expect to be dedicated moving into 2021.

John, I appreciate your commitment to being on the ground and staying informed. Please drive safely, or maybe you've pulled over since your connection sounds good. As I mentioned earlier, we are entering the RFP season for annual work. Based on the current outlook for bidding and plans for next year, we do expect a higher level of activity compared to today. If oil prices are favorable, this could begin early next year. If not, there may be some delays. Regarding your question about the percentage of our work that is dedicated versus spot, I can tell you that a very large majority is dedicated. To succeed for both the customer and us, it’s essential to maximize throughput through our assets, so that’s our strong preference. However, in certain areas where partners don’t have a full fleet, we aim to combine jobs and coordinate between different clients. Our fleet can work with one client for six weeks and with another for six months, but again, most of our work is dedicated.

Okay. Just one more for me, and I don't know if you can share this data or not. But when you look at pumping hours per day that you get on your fleet, have you been able to get similar data on the Schlumberger fleet? And can you comment on what disparities exist in the setting?

It depends on the source, which is interesting. We clearly use third-party data that aligns not only in scale but also in trends with our internal data. You've likely heard us mention various third-party data sources in our presentations, and we select those we trust to be reasonably accurate.

And our next question will come from Ian MacPherson with Simmons.

Chris, Michael, maybe worth asking about the playbook for a downside case, just given the direction of the oil tape. Obviously, we've seen divergence with gas and oil. We've seen you move into the Haynesville ahead of the OneStim acquisition. But you've increased your share in your fleet count, I think, with good strategic reasons in the back half of this year even when pricing remains very difficult and margins, on the consolidated level, remain poor, notwithstanding the incremental contribution margins of those fleet adds. But if the activity recovery for the total market slides to the right because of the commodity next year, what would your appetite be to continue to take share and to redeploy incremental fleets? And ahead of that recovery, given the trade-off between wanting to be strategic and ahead of the market, but also just putting unprofitable wear and tear on the equipment.

Yes, certainly, if the activity decreases, it definitely reduces our operations. Our focus is not on gaining market share for its own sake; instead, we prioritize long-term profitability and high returns on our investments and workforce. We are customer-specific; if a strategic customer is performing well with Liberty and wants to grow their market with us, we can negotiate a sensible price. However, if a customer wants to partner with us solely because of our superior performance but lacks strength or has an uncertain plan, we won't proceed without a strategic reason that supports profitability. We maintain open dialogues with our customers, suppliers, and with you. Therefore, while we may reduce our deployment if conditions pull back, our decisions hinge on the strength of our customer relationships and the anticipated returns of those investments over time.

That makes sense. And then a follow-up for me. Could you share any insights as to how you see the OneStim activity cadence unfolding from Q3 into Q4 relative to Liberty's, if you're privy to that and if you'd be willing to share it with us.

We certainly can't share any details about their projections and plan. In fact, we don't have much information ourselves. However, I can say that the recovery from the downturn has been quite strong for them. A month ago, when we examined the data, they were operating a fleet size similar to ours.

And our next question will be a follow-up from Marc Bianchi with Cowen.

I guess, Chris, you're regarded for good reason as a forward thinker in this sector. And I think it's something that hasn't come up on any of the earnings calls here, thus far, and I think it should. The election, obviously, coming up and there's some concern as to what could happen to the industry from a further leaning left government. So just kind of curious how you see that playing out, if you do see a Democrat win and a more democratic Congress? And maybe anything you guys are doing in terms of contingency planning around that.

Yes, it does matter. However, making predictions is challenging, especially regarding future events. We lack insight into election turnout and how different control of the presidency or the Senate might influence policy. Typically, elections feature intense rhetoric and bold promises, but the reality is often more muted after elections. As you may know, about 10% of our activities are on federal lands, where permit backlogs have developed. I recently wrote an editorial discussing the potential impact if permitting and drilling on federal lands were to cease. We can be certain of two outcomes: increased greenhouse gas emissions and heightened pollution. Stopping these activities does not decrease the demand for oil and gas; it simply shifts production from well-regulated, clean operations in the U.S. to other locations. For instance, New Mexico has introduced free college tuition funded primarily by oil and gas royalties from federal lands. While the future is uncertain, I suspect that the upcoming election will not significantly affect the activity levels in our industry in the near term, despite the current emotional climate surrounding the issue.

And at this time, I'm seeing no further questions. I would like to turn the conference back over to Mr. Wright for any closing remarks.

I just want to thank everyone for their time and interest today. And again, thanks to everyone in these tough times. I thank the people within Liberty. I'm thrilled to be and humbled to be partners with the whole Liberty family. I'd say the same thing about our customers. Look, our customers, our suppliers, our partners across the board have shown character and resilience in the face of these challenges and an attitude that we're all in it together. So thanks to this fabulous industry, and thanks, everyone, for their time today. Take care.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect your lines at this time.