Liberty Energy Inc (LBRT) 2020 Q2 法說會逐字稿

Good morning, and welcome to the Liberty Oilfield Services Second Quarter 2020 Earnings Conference Call. (Operator Instructions) 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 can 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 the company's earnings release and other public filings.

Our comments today also include non-GAAP financial and operational measures. These non-GAAP measures include EBITDA, adjusted EBITDA and pretax 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 and the calculation of pretax return on capital employed as discussed on this call are presented in the company's earnings release, which is available on its website.

I would now like to turn the conference over to Liberty's CEO, Chris Wright. Please go ahead, sir.

Good morning, everyone. As we all know well, the oil and gas industry is cyclical in nature, with down cycles testing the strength and resilience of players across the value chain. The current cycle collapse has been unparalleled in recent history, with an oil demand crash leading to a precipitous decline in rig count and an even more violent decline in completions activity, which for many oil basin producers was a complete halt. In the face of these extraordinary circumstances, Liberty applied its core strategy, tenets and principles to guide our team in charting a course to meet the current challenges; enable and support our customers and our workforce; and build an even better business for the future. In the midst of chaos, there is also opportunity. What did we do? And how do we do it?

First and foremost, we stayed in constant dialogue with our customers. Like Liberty, our top tier customers have built businesses with the ability to withstand the current cycle, and they are working hard to manage their businesses to earn the highest rate of return over the long term. We found that our partners evaluated near-term prospects and made rational decisions to pull back activity. In many cases, they pulled back even more aggressively than others. It was simply the right decision, and we worked with them to assure that operations were wound down safely and planning began immediately for restarting operations.

Liberty acted swiftly and in alignment with our partners. As we outlined in our last call, we manage the business around our customers and their expected activity levels over the course of the year. We stood behind our partners, and we remained disciplined in the market. And we did not chase frac activity for the sake of activity. We collaborated and negotiated as partners with our customers and grew market share with all our top customers, entering the second half of 2020. Our engineering team has been quite active with our customers, utilizing this lull in operations to advance understanding and optimization of completion practices across customer asset portfolios.

Another subject of great customer interest is our efforts to enhance next-generation frac fleets and document the trade-offs between various technologies and implementation. Liberty's DNA as a data-driven ESG leader is drawing increasing attention.

Oil basin frac activity bottomed in late May and has been slowly rebounding since then. June was better than May, July was better than June, and August will be better still. This is not to say that things are okay. Things are deeply stressed, but slowly heading in the right direction. We expect to reach double-digit average active frac fleets later this year.

During the second quarter, we also worked decisively to adjust our cost structure, to flex with activity levels and enable us to deliver end of year demand expectations from our customers. We implemented tough measures to preserve cash and protect our balance sheet. We are pleased to report that our second quarter results showcased the successful execution of our strategy. We reported cash and cash equivalents of $125 million at the end of the second quarter, representing an increase of $68 million from the first quarter. This exceeds our total debt of $106 million, leaving us in a net cap -- cash position of $19 million at the end of the second quarter.

Total liquidity at quarter end, including availability under our credit facility, was $207 million. These results came despite an adjusted EBITDA loss of $13 million, resulting from a substantial sequential drop in frac industry activity, most notably in oily basins, which is where we operate. Michael will share our full financial results shortly.

The disruptions to our industry have required sacrifice from everyone in the Liberty family and our broader community of customers and suppliers. We are proud of the steadfast resolve the team has exhibited in these truly trying times. This resolve is evidenced by the greater than 95% return rate from furlough of the Liberty frac crews. These folks are rightfully proud of their accomplishments and commitment to Team Liberty and were anxious to get back to work. The return crews have delivered simply outstanding operational performance on every metric: efficiency; safe operations; implementation of COVID safety procedures; and making our customers feel confident in their choice to partner with Liberty. I am proud and humbled to be their partner.

Where does that leave us today? First, we believe that our competitive advantages; a strong and loyal culture; long-term customer partnerships; a technology-centric asset base; and an innovative engineering approach to completion designs and commercial relationships are central to Liberty, and we will continue to build on all of them. These attributes were demonstrated last quarter when we comped for 97% of the minutes in a day on a plug and perf pad with over 20 well swaps. This performance and customer partnership enables records like this one.

In the last downturn, 2015 to 2016, we dug in with our customers to innovate our way to success. We are doing the same thing this time. The depth of the last downturn brought rapid destruction of available frac fleets and frac companies. We are seeing the same thing this time, but at an even faster pace. 2 of the top 10 frac companies have already entered bankruptcy and another has engaged restructuring advisers. Not only is the supply destruction helping to move the market towards balance, it is also highlighting the importance of having the right partners for the long term. We are in dialogues with several potential new customer partners.

We have always had a highly variable cost structure to match the cyclic nature of our industry. But this cycle down is the fastest ever, forcing us to make significant adjustments to our cost structure. We quickly took the painful action of having our staffed frac fleets to 12 fleets, consistent with customer dialogues about activity levels later this year. We also cut our CapEx plans in half, suspended our dividend and made comprehensive operating cost reductions, which Michael will elaborate on.

Finally, the importance of liquidity remains at the forefront of our decisions. We've always approached our balance sheet with conservatism to both weather and take advantage of downturns. While today is full of uncertainty, I can assure you that we've never been closer to our customers or better positioned to face tough markets and take advantage of profitable opportunities. The continued hard work of the people of Liberty and our unrelenting focus on our customers leave us well positioned to pursue our goal of long-term value creation for our shareholders.

I will now turn the call over to Michael.

Good morning. As we discussed on our last earnings call, the COVID-19 pandemic effect on worldwide demand for oil was rapid and dramatic. The resulting oil price decline drove North American shale producers to shut in production and basically cease fracking for a period in the oil basins where we operate. Our second quarter results reflect the transition to align our cost structure with our dedicated customers' activity levels over the course of the year and our execution on the cost reductions outlined on our last earnings call. We are laser-focused on protecting the business. As oil demand returns, we are setting the stage for the return of profitable activity.

For the second quarter of 2020, revenue declined 81% to $88 million from $472 million in the first quarter, reflecting our oil basin exposure where activity levels fell dramatically and the disciplined approach by our top tier customers to reduce activity because of the volatile macroeconomic backdrop. Our net loss after tax declined to $66 million in the second quarter compared to a net income of $2 million in the first quarter. Fully diluted net loss per share was $0.55 in the second quarter compared to fully diluted net income per share of $0.02 in the first quarter. Severance-related costs were $9 million during the quarter, and fleet lay down and start-up costs, included in cost of sales, were $4.5 million for the quarter.

Second quarter adjusted EBITDA declined to a loss of $13 million in the third -- second quarter from the solid profitability of $54 million in the first quarter. Second quarter adjusted EBITDA was a loss of $8 million after excluding noncash items of over $4 million. We believe the second quarter marks a cyclical low point in frac activity.

General and administrative expense totaled $18 million during the second quarter, a 37% reduction from the first quarter as we enacted swift cost-saving measures early in the quarter. General and administrative expenses declined actually 45% sequentially when you exclude share-based compensation of $3 million and $3.1 million, and accounts receivable allowances of $2.5 million and $2.2 million in the first and second quarters, respectively, a significant achievement in the current environment. The sequential decline in G&A expenses was primarily due to lower personnel costs tied to reduced variable compensation and flexible furloughs, a reduction in IT travel and entertainment, facilities and other costs. Approximately 10% to 15% of the savings were structural in nature, with the remainder tied to cost initiatives that adjust with activity and profitability levels. Net interest expense and associated fees totaled $3.7 million, and we recorded an income tax benefit of $11 million for the quarter.

We had robust free cash flow for the quarter and ended the quarter in a strong liquidity position, including a cash balance of $125 million, which increased $68 million from the first quarter of $57 million. With total long-term debt of $106 million, we ended the quarter with a positive net cash position of $19 million. At quarter end, we had no borrowings drawn on our ABL facility and total available liquidity was $207 million, including $82 million available under the credit facility.

During the last earnings call, we outlined several targets to protect the business through cash conservation, liquidity management and maintaining balance sheet strength. The rapid deterioration in the frac activity led us to act swiftly to navigate this unprecedented economic challenge. We built Liberty to weather the bad markets and thrive in the good ones. Our flexibility and our cost structure and the strength of our balance sheet enables us to manage the potential macroeconomic risks, such as the effects that the resurgence of COVID could have on oil demand as well as take advantage of opportunities that arise in times of distress.

Let's look back at these actions we discussed in the last earnings call. First, we reduced our staff frac fleet count to 12 fleets after discussions with our dedicated customers to match their projected completions demand in the latter part of 2020. This reduced our cost structure by approximately $170 million on an annualized basis. We then furloughed the frac crews that were not actively fracking in the quarter. The furlough crews returned to work as their dedicated customers start up their frac activity. This enabled us to flexibly manage our cost structure to align with revenue. We currently project that between 10 and 12 crews will be working in the fourth quarter.

Secondly, we suspended bonus plans in the 401(k) match, which, coupled with lower base salaries and cash compensation for our Board, reduced our cost structure by approximately $50 million on an annualized basis. Third, we reduced capital expenditures projections to $70 million to $90 million range for the year, which is approximately 50% of the original 2020 budget. Capital expenditures for the second quarter were $13 million compared to 13 -- $33 million in the first quarter.

Fourth, last quarter, we announced a suspension of our quarterly dividends until future business results support reinstatement. Fifth, our supplier partners have always been a key part of our ability to weather the cyclical nature of our industry. We are seeing input cost reductions of 10% to 30%, which will continue to roll through in the second half of the year. Sixth, we instituted a temporary furlough program for operational crews and corporate staff.

These definitive actions set us up to navigate the turmoil in the frac market during the second quarter, as showcased by the strength of our balance sheet exiting this extraordinary period. We have both the flexible cost structure and the balance sheet to manage through potential challenges in the market until world exits the uncertainty of the COVID pandemic. As we said on the last call, we are committed to our strategy of disciplined growth and returning cash to shareholders, but this requires us to protect the business first.

And with that, I will now turn the call back to Chris before we open for Q&A.

COVID has thrown the world for a loop. The public health impacts are truly heartbreaking. Fortunately, the full force of the modern world is deployed in response, developing therapeutics, vaccines and arresting transmission so that we can put this scourge behind us. The trajectory of future global oil demand will largely be tied to the success and timing of COVID mitigation.

Over the last several weeks, world demand for oil has rebounded strongly and world production of oil has declined significantly, mostly due to OPEC+ production cuts. Further, today's very low producer investment levels in the U.S. and around the world will surely lead to significant reductions in the world's oil production capacity. In other words, market forces are working to bring oil inventories back in balance.

We look forward to fielding any questions that you may have. I'll turn it back over to the operator.

(Operator Instructions) And our first question will come from Chase Mulvehill with Bank of America.

I guess, first, I just kind of wanted to talk about the progression in 3Q and into 4Q. I guess, firstly, on 3Q, could you maybe talk about the average fleets that you expect in 3Q? You gave us some color around 4Q. But maybe expectations there for 3Q and EBITDA per fleet as we get into 3Q, and then more importantly, into 4Q.

Yes. Chase, as we move forward here, we're going to be ramping up from where we are now to where we think we'll be in the fourth quarter, which is between 10 and 12 fleets. And as you've seen, this is going to be a slow progression as you move with earnings into the fourth quarter, as we get to sort of a more reasonable balance of the amount of fleets. So I really wouldn't look at it on a per fleet basis. You've got a lot of fixed costs that you're going to have to subsume in that third quarter period, but we should be back into a better balance by the fourth quarter.

Okay. All right. And a follow-up on the 10 to 12 active fleets in the fourth quarter. Could you maybe just talk to how many of those 10 to 12 fleets are actually working for new customers?

Yes. The vast majority will be existing customers that are coming back to work. I would say that's the large majority of it. We are in several dialogues with new customers. So there may be 1 or 2 or more than that in there. But dominantly, it's the same customers we brought to the dance.

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

I was wondering if you could touch on pricing. Maybe if you can potentially describe how it compares right now to the second quarter and whether there's any uplift in the fleets that are going to work in the third and fourth quarter compared to whatever pricing might have gotten to in the second quarter.

I mean, look, the short summary of pricing is it's bad. And the reason is, what moves the pricing of something is when you have this drop in activity, you've got lots of staff to active fleets when this -- when the pandemic hits and activity declined, and they've got to be pushed out of the marketplace by some mechanism. And that's always a combination between price and customer choice. So, Voie, if you looked at it, we did not participate in that market. But if you were May or June, and you wanted to bid and win a pad to fill a hole and schedule, just pricing, insanely bad.

For us, again, we follow that pricing, but we don't really participate in it very much. But we have very candid dialogues and discussions with our customers. Of course, they've been -- we've been hit by a terrible decline in activity and pricing, so have they. So they're struggling to meet just, I think, of what oil prices did in Q2. So pricing reset, quite a ways down in Q2, even for the dedicated ongoing fleets. And for most of that, that's sort of a negotiation. Most of that pricing will stay until the end of the year, and things will start to move back up in January. Some pricing will come up before then, obviously, spot pricing or filler pricing. It is moving up now because so much capacity is getting pushed out of the marketplace. And I think the uncertainty of having low quality or lower grade partners because they were cheap, that calculation many made, I think, is being shown to be maybe not a great trade-off.

Okay. That's helpful. So if you wrap all those things together, is it fair to assume that the pricing that you expect to have in the second half of the year is not going to be very far off from what you had in the first quarter of '20?

Not -- no, no. It will not be back to the first quarter of '20. There's a reset, lower in the second quarter of '20. And yes, it won't move up much from that this year. It will start to move up meaningfully in January. It may move a hair up. It will move a hair up in the second half. But the big difference between the second half of '20 and Q2 of '20 is more are going to be utilization, larger number of fleets working, fuller scheduled, better fixed cost absorption.

Got it. Okay. And then just 1 follow-up. I got the 4.6 fleets last quarter and heading to 10 to 12 but I don't think you've called out how many you have active right now. Did I miss that?

That's correct. We haven't -- we did not announce that as sort of it's going to move up slowly. As Chris pointed out in his prepared comments, June was better than May, July better than June, August better than July, as that moves forward into sort of heading into the October time period.

And we don't call out the specific numbers, mainly because it's not a -- our objective is not to have how many fleets can we get out there. Obviously, there are things we can do to grow that number faster so we tend to call out numbers that are very important to our strategy. What is important to us right now is keeping our team, our technical capabilities, our equipment strong; keeping our relationships with our customers strong; and selectively, when they make sense, growing our customer partnerships. But it's all the interaction of those things that make the decision whether to deploy a fleet or not. But it is moving up. It's been moving up, and it will continue to move up.

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

Michael, for CapEx as a percentage of revenue, what do you expect for each of the next 2 quarters? And how much room for improvement is there, there? What's your target run rate level or range for that percentage?

Tom, I think really looking at the target run rate over the next 2 quarters versus revenue, it probably doesn't make any sense. I mean, really, I think you got to look at this long term. We are in the -- if you're looking at it on a maintenance basis, we're in the mid-single digits, in that sort of 6 percentage point range. And then when we add growth, we got into the 10s.

And is that sort of the best you think you could do there? Or do you think there's room to take that down a bit further over the long term?

That's on a normalized basis, right, I mean when we look at that, if you're thinking about that on a sort of a normalized revenue basis.

Okay. And then since last quarter's call, Energy Recovery has really dramatically overhauled its commercialization plan for the VorTeq system, exiting exclusivity agreement with Schlumberger and converting the missile to a modular single PX skid design. Ron, you sounded encouraged by this new skid models technical performance in a recent simulated well test with the Liberty crew and equipment spread. Have you resumed actively trying to secure a customer who would be open to conducting a live well test with this new skid design? And what's the earliest we might see that happen?

Certainly, Tom, we're back in those conversations. We were on the verge of doing that before the world turned upside down. And so we are back on that path today. The testing that we did do in the simulated well conditions identified some further opportunities for improvement. So those improvements are underway at Energy Recovery right now. But that said, we are back in dialogue with the same customers we had been talking with in the past. And I think when things have stabilized, and they've got their feedback underneath them, we'll be back looking at a live field test. And so I hope that happens, maybe sometime in Q3 if we find the right opportunity, but I'd certainly think no later than early Q4.

And our next question will come from James West with Evercore.

Chris, how are you thinking about returns in this current environment? I mean, obviously, 2Q, terrible for everybody; 3Q, you want to get some back to work with certain customers and 4Q as well, but the pricing is not particularly great, but you want to be there for your customer base. And I know you guys think about returns on a -- over a full cycle basis anyway. But how are you managing utilization, price, returns versus the other objectives -- strategic objectives that you have, gaining more customers or aligning with more strategically important customers?

Yes. James, I think you hit the right issues there. Returns in the long run, the essential thing is to have the right strategic customers that are willing to change practices and get better, not just buy a static commodity. We don't deliver that. And so there are customers, if that's their plan, it's just not a match for us. But I would say there's obviously a large avenue of great, strategic customers for ours. We love the customer base we have today, but there's no question it will grow this year. But yes, and that's the metric. It's a balance between not ridiculous pricing today. And we have those very candid dialogues, "Hey, you're stressed, we're stressed." Where is the right balance to help each other get through this year? And then find those partners that, through efficiency, through technology, can get a differential advantage from Liberty. So they can get an increase in their returns by partnering with us, and we can get an increase in our returns by partnering with them.

So James, you say it right. That, yes, if we wanted to do everything to maximize our returns, the whole world only lasted for Q3, we would do very different things than what we do. But fortunately, the world is going to last longer than Q3. So in Q3, it's -- and a key thing is our team. We had to shrink our team. We've never done that before, but all of the crew leaders, all of the technical prowess, all of that is still here. We've got to rebuild those crews back next year, but all of the crew leadership, all of it is still here.

But yes, it's finding the right partners that we can have a value proposition to create value together over the long run, and then help -- in these tough times, helping them get through their plans and through all times. And again, we're pretty excited about it. The dislocation of the last downturn was awesome for customer relationships and new partners for Liberty that have benefited us for years, and I think we're seeing that same kind of stuff unfold here.

Yes. No doubt about that. Well, a follow-up for me on technology. There's some interesting things coming to the marketplace. Ron just answered, I think, one of the questions on one technology, but there's a lot of other stuff out there. Are you -- now that the dust has somewhat settled, are your customers willing to engage in technology conversations, try new technologies? You guys have always been a leader here. But I know for 2Q, it was just, let's hunker down. But in 3Q, are we starting to see companies say, yes, we'll give that a shot and see if we can get better fractures, better more stages, et cetera?

Absolutely, James. Because I think when you go through a crisis -- when you're cruising along, our industry is always relatively lean and mean on people. So people are following systems, they're implementing operations. And you got all these ideas, and people are like, "Nah I'm just trying to keep the train on the tracks." So you always have some resistance to get new ideas tried. Then when the world gets rocked and the operations are reduced, yet today, it's a fantastic time to say, "Hey, golly, I know you've been bugging us about that for the last 6 months. Let's take a look at that. Let's bring our tech team in. Let's gather that data."

So we are absolutely using this lull in frac activity to actually increase technical efforts on frac design, on evaluation of properties and variations of reservoirs across the basins of our different operational technologies. So yes, this is a technology-rich engagement period right now.

Our next question will come from Waqar Syed of AltaCorp Capital.

Mike, is there -- do you expect to be EBITDA per crew kind of positive in the third quarter or fourth quarter?

I would say that, definitely, by the end of the year. We'll have to see. I think, probably -- again, you've got -- fixed cost absorption will make third quarter -- would make the third quarter very tough.

Okay. And when do you expect to have EBITDA per crew in excess of maintenance CapEx?

Again, we're kind of far to sort of like -- again, we're in the middle of sort of the COVID pandemic with incredible uncertainty in the market at the moment. So any sort of detailed projections like that really will change within 30 seconds because -- depending on what happens with oil demand across the world. So we -- again, we are managing to sort of -- the best liquidity position that we have, the strong balance sheet that we have, best partnerships with our customers. And that's the way we're managing the business.

Because the numbers we report are the roll-up of all the numbers, on a crew by crew level. If you look at the incremental economics there, it's a different scene. But it depends how many crews you have for fixed absorption and the utilization of those crews. So pricing probably isn't quite as bad as you think it is, but we only report the whole pie.

Fair enough. And then for the 10 or -- to 12 crews that you expect to have working in the fourth quarter, has the pricing being determined for those? Or is that still a moving target, it depends on what the supply demand dynamics are in the fourth quarter?

For a number of them, it's already determined because that's negotiated. Those fleets are already back up and running. And we've sort of agreed we'll run at this level for a certain time period. And generally, that's to the end of the year, kind of get through this period together. Some of those crews are still in dialogue or discussions. So yes, there's certainly some movement there that will be somewhat impacted by supply and demand.

Okay. Fair enough. And then for next year, where are the discussions right now? And when do you think -- do you expect to have more crews running by first quarter or still too early to make that determination?

No. I think almost certainly, we will. Yes. Outlook for us next year, actually pretty good, pretty good. You've got a reshuffling of the deck of customers and even percent of work from larger customers. So the outlook for us next year, yes, I would say, quite positive.

Let me give a little math. We'll end this year with probably in the oil basins, maybe 100 frac fleets working. By our bottom-up analysis, basin by basin of crews, it takes about 165 crews in the oil basins to keep U.S. oil production flat at our now projected end of year oil production rate. Probably need 25 or 30 crews to run the gas basins, to keep gas production roughly flat. So we've got to go from -- and again, if you add in the gas basins, maybe we'll end this year 125, 130 crews. Probably need 190 to 200 just to hold U.S. production flat. You need another 80 or 85 crews to grow U.S. production by 1 million barrels a day, so -- which I do not believe will happen next year. I think we've seen tremendous discipline from the customers, I think that message, and that push to get returns up. But the average active frac crew nationwide, next year, will likely be meaningfully higher than it will be at the end of this year. And Liberty's market share of whatever activity is there will probably continue to migrate up.

Now Chris, in that analysis, what do you assume with respect to further efficiencies in -- from the pressure pumping crews? Because just from your example alone, it feels that the crews continue to get more and more efficient.

They do. And in our analysis, we assume continuations of increases in efficiency because certainly, that will happen. For 2 reasons: one, technology and the advancements of our crews continue to get more efficient; also, the least efficient, the lowest quality crews are disappearing. So you have sort of 2 effects that are going to move efficiency up.

But if you look, Waqar, at sort of -- so, yes, if each frac crew next year are going to pump more pounds of sand than it will this year -- well, this year might be an anomaly because like only the 8 -- there's sort of a lot of A plus teams out there. But will that continue to rise? Yes. But there's the offsetting factor, that wells that are drilled now is much more infill drilling, less virgin wells. You've got movement of run.

If you look at the last 2 years of oil -- new oil production delivered by a frac crew, it rose amazingly fast from the start of Liberty until about 2018. And I've spoken about this before. Both well productivity plateaued, that actually declined slightly since then. And that decline in average well productivity roughly offsets in continued efficiencies of frac crews. So the amount of new oil brought to the marketplace from a frac crew has actually plateaued the last 18 or 24 months and likely, will be not meaningfully moving next year. We'll have a continued -- a little bit decline in the average quality of the location drilled that will roughly offset the increased throughput and efficiency of increased crew efficiency. So yes, all of those things are factored into our sort of bottom-up macro analysis of both U.S. oil production and demand for frac crews under various scenarios.

Thanks for the questions, Waqar.

Look, do you have -- can I ask one more or...

Go ahead, Waqar. I can't cut you off. I'll try to be quicker. I'm the problem, not you.

All right. I now in terms of your outlook for crew increases, do you think that they go back proportionally to the different basins on the same kind of proportion as we saw previously? Or is it more shifting towards just Permian and maybe a little bit going to Bakken, Eagle Ford and DJ?

Yes, [choice B], yes, I mean, look, we started in the Rockies, right? So our crew count was over -- we have larger market share in the Rockies. But when you have a reset of oil prices lower, transportation and differentials tend to matter more. So yes, activity will shift. The total industry activity will probably be a little bit more concentrated in Texas than it was. And Liberty's crew, our representation will probably be more in line with the marketplace. So yes, we've had more crews in the Rockies than we've had in the southern regions until this year. And going forward, you'll probably see more of our crews will be in Texas than on the Rockies. We won't shrink market share in the Rockies at all, but market share will move that -- we'll grow market share in Texas. We'll probably at least hold market share in the Rockies and the work will skew a little bit more to Texas. So yes, you'll see a different -- a shift -- a slow shifting following customers and activity level of where Liberty's crews are.

And our next question will come from George O'Leary with TPH & Company.

I wondered if you could help frame -- it's tough for us to get insight into frac count given all the different data sources, showed different numbers out there. But fleet utilization is even more opaque so I wondered if you could help us think through fleet utilization as we progressed through the second quarter. And then what you're seeing in June and July relative to either the April or May time frame, but just trying to get a better sense of that fleet utilization given we don't get much information on that.

Yes. Well, fleet utilization is always lower when things are changing, right? So in April and May, you had fleets that were working that were then shutting down, right? So those guys are not gone immediately the day you pump the last day, that equipment has got to be demobbed and stored and taken care of. We don't cannibalize our equipment. We keep all of our equipment in top shape. And so we have a little bit of a reverse of it now, right? People are coming back to work. So a crew goes out, but all those folks come there early. That equipment is -- they're working on that equipment. They're working on their processes and planning before they start fracking again.

So as you start standing crews back up, again, if you start fracking in the middle of July, it doesn't mean that equipment's first touched on July 14 for a July 15 start, right? You got to get people at start, ready before that. So most of the work we do, and certainly, most of the work we'll do this year, is dedicated work. But as you go through the lay down in April and May and stand ups, there's definitely harms to utilizations. We'll add some spots the long term, but some temporary work. If we're testing out a new customer, we want to see if there's a good partnership there. Or if we've got a gap. Somebody wants to restart their operations, sometimes, the customers want to restart a little slower, too. We want to finish off this pad, and then we got to get stuff ready over here. So we may have some gaps, some poor utilization as you get going. But once you get a month or 2 into a crew running, we should be back to efficient and smooth.

Great. That's helpful. And then the -- just a question born out of curiosity more than anything else. The 97 minutes of the day fracked is an incredibly impressive stat based on all the work we've done around how many hours a day you could pump a pressure pumping spread. I wonder if you could speak a little bit what enabled you all to execute that, if there was a piece of technology that allowed you to do that, what limited the swapping between well time. That's just a fascinating stat.

Yes. It's a combination of things. First of all, think of that crew, that's a crew of a bunch of supervisors, the guys who were stars and rode the leadership. And so that -- it's a very talent-rich crew. And of course, the goal at Liberty is over time to build -- all of our crews every year, the average experience level within Liberty of those crews is going up. So I hope that, that awesome A team, all-star team that delivered that, that we have fair amount of crews that look like that several years from now as the people are seasoned within Liberty. There's technology. There's customer cooperations. There's some automation we've done on pressure testing and a few other things. But I don't want to say too much, except to say that it's the combination of the humans in Liberty and a great partnership with a highly efficient customer that, since we've started working with them, we've just continually broke their legacy records. And I think it's fired them up as much as us up to keep breaking those records.

Our next question will come from Sean Meakim with JPMorgan.

So a lot of questions on utilization this morning, which makes sense. Could we maybe just get a little bit more feedback on how you're trying to manage at these low levels of activity? How you're trying to manage to -- across the fleets to maximize utilization in each basin? So you've got varying degrees of challenges across the northern basins and then in the southern ones. Just curious how you're trying -- as you look forward in the back half of the year, how you're going to try to achieve sufficient scale in each basin while also managing the other parts of how you deploy your fleets to maximize uptime in this current environment?

Sean, it's Ron. I'll maybe talk about that from a couple of levels. First of all, I think, as we've already said on the call, the vast majority of the work we're going back to do is for our dedicated customers. And so they bring to us a pretty complete schedule, generally speaking. And so that helps an awful lot in terms of making sure that utilization for those crews remains high. We've been working closely with them really since April to think about those plans for returning to work and how that's going to look for us, with the goal of maximizing utilization as we bring a crew back off furlough and put it back to work in the field. We obviously have some customers that don't have a complete schedule. And so we're working closely with them, asking them potentially to be a little bit flexible on timing so that we can level load our fleets to the extent possible. So where we can, we're shuffling the schedule around a little bit, asking somebody to go a bit earlier or a little bit later, such that we can slot them into gaps or opportunities that we have on an existing fleet.

Okay. Fair enough. I appreciate that feedback. The other question. Chris, as you -- we've spoken over the years. You all have proven to be countercyclical in your investment strategy. It never feels good to be a contrarian, particularly when times are tough. You did it successfully in '15 and 16. But of course, we would argue that the forward outlook is much more challenging than it was even back then and the industry's outlook has changed. Perhaps that creates more willing sellers, but also makes -- putting a bid out there more daunting. Just curious in terms of like the broad type of environment that you'd like to see or you'd envision that would make sense to do something more transformational or just to do something more meaningful on an M&A basis. Is this the type of environment that you'd be looking for? Or what are the types of parameters that would make sense from a macro perspective, leaving aside the specifics of the deal itself?

It is that type of environment. As I'm sure you know, virtually -- not virtually, but a large percent, the majority of the stuff that's out there and companies out there are for sale, so -- and some aggressively so. So yes, we have been very active in the last few months looking at all sorts of opportunities. But again, we've not been much of an acquirer. So that doesn't mean anything's going to happen at all. But if something is compelling, really the single metric is, can we grow per share value via this asset acquisition or a larger transaction or whatever? But there's a surplus of horsepower. So what does it bring in terms of technology, in terms of economics? There's lots of factors. And so I guess my short answer is, yes, this is the type of environment like we saw in the first half of 2016. Does it mean we'll do anything? No. But does it mean it's more likely? Yes. But I would say, just too early to say, but we're very active in that. And I think you'll see a number of deals in the industry. And whether Liberty will be in one of those or not, I guess only time will tell.

Our next question will come from Blake Gendron of Wolfe Research.

I want to follow-up on the efficiency comments. It seems like the value of marginal efficiency that you deliver is far greater than incremental stage pricing from here, underpinning some of your comments in the prepared remarks. I'm just wondering, we've talked about performance-based contracts for other parts of the North American oilfield. I know that pumping does employ some performance metrics in part. But I'm wondering just now, as we're hitting sort of a steadier state in U.S. land, if there could be a more concerted shift to a performance-based commercial model for pumping and what that would look like.

Fortunately, I would say, pumping pricing by its nature is performance-based because you're paid by a stage that you put in the ground. So it's -- we don't rent our fleets on a daily rate. So how much of the time we're fracturing impacts our economics. We even have -- with a number of customers, we have an even more dramatic performance pricing where a certain number of stages are x price and every stage beyond that is at a discount to that price. We've used that structure a lot to incentivize our partners, our customers to, hey, if we can figure out how to move faster, we're going to make more money getting more stages done at a day, and you're going to pay less to get your well done.

Now even without incentive pricing past a certain stage, they still make more money and have cheaper wells if they get it done faster. There's tens of thousands of dollars of fixed daily costs out there independent of the frac spread. I've filled these numbers out there before. But if we get a pad done 10 or 20 days earlier, that saves $0.25 million to $0.5 million or more on that well and brings oil earlier. So it is one of the things we like about the frac business versus the drilling business. I think the drilling companies and technology have done awesome stock, but that's sort of charging by the day model has made it tough for them to capture much of that value. Not that we don't have challenges capturing value too because our market is a little too fragmented.

But yes. And we're always trying to find other ways with customers to align our incentives better so that, hey, if we save money, we share the savings together. If we get stuff done faster, we share that together. But I would say we have pretty -- I would say, very good alignment can always be better on economic incentives with our customers. Great question, Blake. I'm sorry, I'm too general, but there's just many different ways to slice that.

No. Absolutely. And that's on surface efficiencies, and I totally get that. You talked about the productivity trends. Obviously, that's going to be important moving forward here. To the degree that you can measure the productivity impact of the data, especially that you leverage, would there be a scenario in which you could participate from a productivity standpoint in these stages, demonstrating that you had a certain amount of productivity per stage? I don't know how you would measure that or even demonstrate that. But you seem to have a better grasp of what's going on in the subsurface than most of your peers.

So we've been less successful there, not completely unsuccessful, but I would say less successful. It's come early on, we had some very different ideas, particularly in the Bakken, that have now been widely used and are now normal in the Bakken, but there was resistance to them. And early on, we were a brand-new company, we did bring to 2 customers a deal that if we don't deliver x amount of productivity increase, we'll give you the extra completion cost money back. But if we do, here's the pricing for that sort of risk. You sort of insured frac design. But of course, they worked swimmingly. And so after people know they work, well, they don't need to buy insurance anymore. So we did a little bit of that. I would say the biggest benefit we get today is really just more in the stickiness of customer relationships. If we're bringing better ideas and we're making customers' wells better, they know technology is going to continue to evolve, they're going to go and develop in different areas. And I think they get a comfort factor that it's better to be partnered with Liberty.

And stickiness matters to us because if we have 1 customer through a 3- or 4-year period, we can just do so much more efficiency wise which helps our profitability and our customers' profitability than if we've got a different customer each year. Even if that fleet is fully utilized with 3 different customers over 3 years, that's not the same value proposition for us as a fleet with the same customer for 3 years. So we get indirect benefits, but we're not getting a percent of the increased profitability from our operators from better frac designs. But I mean they put the money out, they own the land, they ultimately make the decisions. We get it. We want that. And I think we get some of it indirectly, but that's just part of our partnership. They're in the business of maximizing their returns on the acreage they lease, and we want to help them do it.

Yes. That's totally fair. One more, if I could sneak it in. Shifting gears a little bit, it seems like the tenor of the legislative conversation in Colorado has shifted. As of late, the governor came out and said, he'd rather let Senate Bill 181 kind of work its course as opposed to some of the other regulatory frameworks that have been proposed. I'm just wondering because it may have been lost in sort of the noise of the pandemic and decreasing activity in the Rockies specifically, is what you're hearing now a major step change? And is it a big deal for your customers and you by design just moving forward over the medium to longer term?

Yes. I mean, I don't want to overstate it, but it's a meaningful positive. We've had -- there's better dialogues with many different ways and parties throughout it all. But yes, I think we're -- politically, we're definitely in a better place now than we were 3 months ago and than we were 12 months ago. Is it -- Colorado is the best place to drill oil and gas wells but we're not there, but it's a positive development for sure. I think we have some more certainty and more clarity over the next few years. So yes, it's very positive. And I think, yes, it's a good thing, it's a good thing.

Our next question will come from Ian MacPherson with Simmons.

Chris, you laid out a good case for demand recovery next year based on the requirements of production thresholds. And in order to get pricing back in a better place, the other consideration, of course, will be culling supply. So if we had, I don't know, 20 million horsepower in the U.S. at the beginning of this year, having already called the fleet by 20% or so late last year. Maybe we could quibble around those numbers. But how much of that capacity do you think is going to be challenged competitively as we get back in the saddle next year? And also, maybe if you were -- or Ron, could share any thoughts around how the useful life of some of your critical components in the pumps and the power side may be adjusting with more slack in the market?

Yes. I'll start, and then I'll turn it to Ron to talk about some of the efforts we've made on technology to expand useful lines and reduce the total cost of ownership of equipment. But yes, look, there's been relatively low investment in equipment the last few years, both in a much smaller number of new build fleets than attrition, and just people -- and of course, people now, we do not do this, but I would say it's normal industry practice to cannibalize parts off all the parked equipment today. So like -- that's again, where we just take this longer term focus. Our numbers for a certain quarter reflect a certain way we run our equipment and others might reflect a very different way of the way they manage their equipment. It's really just time shifting, it's not cost reducing.

But there's a lot of attrition in the marketplace. There will continue to be. Will there still be issues of too much frac capacity in first quarter of next year? Yes. Will it be better than it is today? Yes. It will be a lot better than it was 30 or 60 days ago so there's progress being made. But I think we're going to move towards a market that will be a little bit from equipment specs, bifurcated. The larger players -- and there's just a growing push coming out of this downturn to have. I want to minimize my environmental and community impacts. That's a Liberty sweet spot. We've been working on that. And so there's -- there will be a growing desire for that. And I think it's a very small number of players that will have offerings to deliver there.

And so a year from now, there'll be sort of legacy equipment markets that will still be large. It will still be the biggest piece of the market. And then there'll be sort of next-generation equipment markets that will be -- the supply and demand and pricing will be different in those.

The other thing that will help with pricing is, everybody had to shrink, right? We talked about our shrinkage. We -- by the end of this year, as I said, we'll probably have 100 or so fleets running. Wow, that's a lot better than we were a month ago, but that's still very low. And then as I made that math out, you're probably going to see 50 to 100 fleets more, on average, needed next year. So those fleets have to stand up, even if they're legacy equipment that's sitting around, like there's no humans on that fleet. Are you going to go hire brand-new and staff a frac fleet to build a team and drive it out there for the crappy pricing of today? No, no. So the next big driver of pricing moving is when demand passes the fleets that are easily staffed from people that are on your team already. They might be in furlough, they might be on reduced comp. But that's one level of bring back when you're hiring new people and that's what it will take. That will mean starting late this year for most people and certainly early next year. That will be a meaningful move up on pricing across the fleet types.

Yes. Maybe just a few more thoughts on your question, just in terms of longevity for the various components on the pump. I guess -- I think we've said this in the past. We probably think about that in 2 different ways. There are some components on the pump that we specifically select from a certain manufacturer, engine and transmission, for example, based on our experience with them and our belief that they are the best asset to put in the field. And for those particular assets, it then comes down to how we operate them. And so we continue to think about the best possible way to run an engine and a transmission, ultimately, a pump in its entirety to optimize the lifespan for those assets and to achieve the lowest possible cost of ownership for those. And then as you move further down the pump, particularly to the fluid end and the power end itself, we've maybe inserted ourselves a little further into that world. We saw opportunity there to go a bit further back in the supply chain and work closely with the manufacturers there to optimize the design of those. And so we've been working over the last 12, 24 months, maybe even a little longer than that, on metallurgy in the fluid end, for example and exactly what that stainless steel should be, what the internal design of that should be, how fluid should flow through a fluid end to best optimize the life of that fluid end and the valves and seats that are in it. And then the same thing with the power end, thinking about exactly why it is a power end fails, and what we could be doing to that power end to make it a better asset. And so our exercise there has been a little different than it has been for the other components in that working closely with a key partner there. We're a bit further back into that design and engineering process. And I think results are quite positive, and I think we continue to expect to see opportunity for further improvement there.

That's great. And Ron, it doesn't sound like stretching your hours through borrowing more rotational capacity on site has really been part of your strategy. Do I infer that correctly?

No. That's absolutely correct. We -- if you drove past one of our yards, you would see that we have parked our fleets in pristine condition, and those fleets remain fleets. So a fleet that's out in the field today is the same as the fleet that was out in the field in the past. We're not having to take a fleet from 20 pumps to 30 pumps to improve efficiency.

And our next question will come from Scott Gruber with Citigroup.

So Chris, just continuing on the pricing question. We agree that there's likely improvement when idle pumps need to be reactivated. I guess the concern is that the margin will still be fairly weak by historical standards and relative to the returns that you look for on your equipment just given the competition out there. Do you think there will be a time where you simply need to draw a line in the sand and say, we're a premier operator, you want an incremental spread from us, you're going to have to pay a premium so we can run a fair rent for our services rendered, even if it puts you in a spot where you may have to sacrifice some share? And if you think that's going to be needed, kind of what level of fleet activity do you think you'll have to make that decision?

So I would say, we've been doing that since the day we started the company. Is there an increased desire for Liberty versus the other people? Absolutely. If we had a customer that viewed us the same as all the other pumpers, they're just -- they wouldn't be a customer. That just wouldn't be a fit for Liberty. So Scott, I would say, look, we are doing that. But are we going to get to a place where we have a posted price lift and it never changes? No. And we don't want to because we have a partnership mentality. Some -- our customers, a few years ago, getting $100 for their oil, and then they're getting $25 for their oil, and then they're getting $60 and $50. It changes every day.

So we went into a cyclical business knowing it was a cyclical business, and we're not going to de-cyclicize it. So we just have to live with that so -- which is why when we look at things, and like our compensation for the executives and our bonuses in the company, they're about return on capital employed over longer time periods. We've got a mid-20s return on cash employed in our business over the history of our company, so -- and do we think that will go way down in the next decade? No, absolutely not. Is it low right now? Yes, yes. But no, I don't think our industry is actually getting structurally worse. I would guess, just a guess, that the next 5 years will actually be structurally meaningfully better than the last 5 years. That's a guess for just supply and demand and forces that are affecting players in our industry, but we'll see. But I get where you're coming from, Scott. But it's -- you just got to think of the people on the other side of the table as well. So it's a partnership.

No. Understood. And we agree that the structure should get better, especially as people capitulate on growth. I guess the genesis of the question is really, will there be a time needed where basically you and other premier operators just have to draw a line in the sand if you don't think we're going to get back to a pricing structure that is really adequate for your services, you do the -- premier operators just have to draw a line in the sand and they saying say, we need any differentiated pricing here incremental to kind of what you're getting vis-à-vis your competitors today. Is that something that can naturally happen? Or is it something you're going to more actively pursue?

Well, it's -- I would say -- you could even say dialogues we have. We have a lot of, obviously, friends in the industry, and they'll tell us exactly what they -- they've bid out 13 frac companies, and this is what we see. And now the better companies won't bid out 13, they might bid out 6 or 8 or something like that. But no, I'd say there is a case now where you may see a slumping of pricing for the top tier players. And then you may see meaningfully, in some cases, dramatically lower pricing from people that are just -- they're just trying to cling on. And I would say we, here, more today -- yes, they were 20% cheaper than everyone else, but we're not going to use that. That's not a -- we don't consider those prices. We're looking here. But I think among the better players, I think the discipline today is actually reasonable given the state of the market. It's reasonable. Better than it was 3 or 4 years ago in the last downturn.

This concludes our question-and-answer session. I would like to turn the conference back over to Chris Wright for any closing remarks. Please go ahead, sir.

Thanks, everyone, for your time today. Sorry if my answers were a little long-winded, but this is our once-a-quarter time to talk through some of the issues. We appreciate all your interest in Liberty. We appreciate the Liberty family, and our customers and our suppliers. And we wish everyone health and wellness in the coming months, and we'll talk to you in the fall.

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