Liberty Energy Inc. Q2 FY2020 Earnings Call

Good morning and welcome to the Liberty Oilfield Services Second Quarter 2020 Earnings Conference Call. All participants will be in a listen-only mode. Please note 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 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 including 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 in 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, 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 declining completions activity, which for many oil basin producers, was a complete halt. In the face of these extraordinary circumstances, Liberty applied its core strategy tenants 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 did 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. 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 managed the business around our customers and their expected activity levels over the course of the year. We stood behind our partners, and we remain disciplined to the market. 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. 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 showcase the successful execution of our strategy. We’ve 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 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 results 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 we're anxious to get back to work. The return crews have delivered 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 pumped for 97% of the minutes in a day on a plug-in per pad with over 20 well swaps. This performance and customer partnership enable records like this one. In the last downturn, 2015 to 2016, we dug in with our customers to innovate our way to success. We're 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. Two of the top 10 frac companies have already entered bankruptcy, and another has engaged restructuring advisors. 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 reducing our staff 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 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's effect on worldwide demand for oil was rapid and dramatic. The resulting oil price decline drove North American shale producers to shut down production and basically cease fracking for a period in the oily 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. And as 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. Activity levels fell dramatically, and the disciplined approach by our top-tier customers reduced 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 laydown start-up costs including the cost of sales were $4.5 million for the quarter. Second quarter adjusted EBITDA declined to a loss of $13 million in the 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 non-cash items of about $4 million. We believe the second quarter marks a cyclical low point in frac activity. General and administrative expenses totaled $80 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 we exclude share-based compensation of $3 million and accounts receivable allowances. 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 with 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 sheets. 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 of the resurgence of COVID could have on oil demand, as well as taking 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 the projected completions demand in the latter part of 2020. This reduced their cost structure by approximately $170 million on an annualized basis. We furloughed the frac crews that were not actively fracking in the quarter, as furlough crews returned to work as their dedicated customers start up the frac activity. This enabled us to flexibly manage our cost structure to align with revenue. We currently project between 10 and 12 crews will be working in the fourth quarter. Secondly, we announced suspension of our quarterly dividends until future business results support reinstatement. Finally, as supply partners have always been a key part of our ability to weather the cyclical nature of our industry. And we are seeing input cost reductions of 10% to 30%, which will continue to roll through in the second half of the year. 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 the 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 these scores 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 filling any questions that you may have. Turn it back over to the operator.

Thank you. We will now start the question-and-answer session. Our first question will be from Chase Mulvehill with Bank of America. Please proceed.

Hey, good morning gentlemen.

Good morning Chase.

Good morning. I guess first, I just kind of wanted to talk about the progression into 3Q and into 4Q. I guess, firstly on 3Q could you maybe talk about the average fleet, if you expect in 3Q, maybe 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, 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. 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. We should be back into a bit of balance by the fourth quarter.

Okay. All right. And the 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 one or two or more than that in there, but dominantly it is the same customers being brought to dance.

Okay. I'll turn it back over.

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

Thanks. Good morning.

Good morning, Chris.

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, they're 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 bad. And the reason is, what moves the pricing of something is when you have this dropping activity, you've got lots of staff active fleets 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 and 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 in schedule, just pricing was 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, we've been hit by a terrible decline in activity and pricing. So are they. So they're struggling to meet just think of what oil prices did in Q2. So pricing reset quite a way 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 fill-in pricing 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 2020?

No, it will not be back to the first quarter of 2020. There's a reset lower in the second quarter of 2020. It won't move up much from that this year. It'll 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 2020 and Q2 of 2020 is more we're going to be utilization, larger number of fleets working full schedule, better fixed cost absorption.

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

That is correct, we haven't. We did not announce that. As it is 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 and moves forward into sort of heading into the October time period.

And we don't call out the specific numbers, mainly because 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 is all the interaction of those things that make the decision whether to deploy a fleet or not. But it is moving up. It has been moving up and it will continue to move up.

Got it. Thanks, I'll turn it back.

You bet. Thanks.

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

Good morning.

Good morning, Tom.

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

Tom, I think really looking at a target run rate over the next two quarters, this is really huge probably doesn't make any sense. I mean, really, I think you've got to look at this long term. We are in the field looking at a maintenance basis. We're in the mid-single digits in that 6 percentage point range. And then when we had growth, we got into the teens.

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. 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 to the board tax system, exiting exclusivity agreement with Schlumberger and converting the mistletoe to a modular single key execute design. Ron, you sound encouraged by this new skit model's technical performance in a recent sea-related 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 skit 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 simulator, 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. I think when things have stabilized and they've got their feet back underneath them, we'll be back looking at a live field test. I hope that happens, maybe sometime in Q3 if we find the right opportunity, but I certainly think no later than early Q4.

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

Good morning, guys.

Good morning, James.

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 an over full cycle basis anyway, but how are you managing, utilization price returns versus the other strategic objectives that you have, gaining more customers or aligning with more strategically important customers?

Yes, Dave, 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 their customers if that's their plan, it is 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 yeah, and that's the metric. It is a balance between not ridiculous pricing today, we have this very candid dialogue, hey, you're stressed, we're stressed, where's the right balance to help each other get through this year? And then find those partners that through efficiency and 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. But, 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 I think the world is going to last longer than Q3. So, in Q3, 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 progress, all of that is still here. We're going to rebuild those crews back next year. But all of the crew leadership, all of it is still here. But yes, it is finding the right partners that we can have a value proposition to create value together over the long run. And then in these tough times helping them get through their plans and through hard times. And we're pretty excited about it. The dislocation of the last downturn was awesome for customer relationships, and new partners of Liberty that have benefited us for years. And I think we're seeing that same kind of stuff unfold here.

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

Absolutely, James. Because I think when you go to a crisis and when you're cruising along our industry, it 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, man, I'm just trying to keep the train on the tracks. So, you always have some resistance to get new ideas try. Then when the world gets rocked, and operations are reduced. Yes, today is a fantastic time to say hey, I know you've been bugging us about that for the last six months. Let's take a look at that. Let's bring our tech team in, let's gather that data. So we were absolutely using this low in frac activity to actually increase technical efforts on frac design, on evaluation of properties and variations of reservoirs across the basins of different operational technologies. So yeah, this is a technology rich engagement period right now.

Right. Thanks Chris.

Thanks, James. Appreciate.

Our next question will come from Waqar Syed of AltaCorp National. Please go ahead.

Thanks for taking my question. Mike, do we expect to be EBITDA per crew 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 costs, absorption will make the third quarter very tough.

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

We are currently facing significant uncertainty in the market due to COVID-19. Any detailed projections can change rapidly based on shifts in global oil demand. We are managing our business through our solid liquidity position, a strong balance sheet, and our partnerships with customers.

Waqar, 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 is 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 to 12 crews that you expect to have working in the fourth quarter. Has the pricing been determined for those or is that still a moving target depends on what the supply-demand dynamics are in the fourth quarter?

For a number of them, it is already determined that's negotiated, those fleets are already back up and running. And we've sort of agreed will run at this level for a certain time period generally that to the end of the year, to kind of get through this period together. Some of those crews are still in dialogue or discussion. 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? Do you expect to have more crews operating by the first quarter, or is it still too early to determine that?

No, I think almost certainly we will. Yes, outlook for us next year actually pretty good. You've got a reshuffling of the deck, customers and even percent of work for larger customers. So outlook for us next year. Yes, I would say quite positive. Let me give a little math will 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 it, and again, if you add in the gas basin, 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 a million barrels a day. 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 crews nationwide next year will likely be meaningfully higher than it will be at the end of this year. And Liberty's market share or whatever activity is there will probably continue to migrate up.

Now Chris, with that analysis, what do you assume with respect to further efficiencies 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'll happen for two reasons: One, technology advances, our crews continue to get more efficient. Also, the least efficient, the lowest quality crews are disappearing. So, you have two effects that we're going to move efficiency off. But if you look Waqar, so yes, is each frac crew next year going to pump more pounds of sand than it will this year? Well, this year might be an anomaly because like only the A crews, there are a lot of A+ teams out there. Will that continue to rise? Yes, but there's an offsetting factor that wells that are drilled now, are much more infill drilling, less virgin wells. You've got movement of run. If you look at the last two years of 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 has actually declined slightly since then. And that decline in average well productivity roughly offsets the 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 little bit decline in the average quality of a location drilled that’ll roughly offset the increased throughput and efficiency of increased crew efficiency. So yes, all of those things are factored into our bottom-up macro analysis of both U.S. oil production and demand for frac crews under various scenarios.

Thanks for the questions Waqar.

Can I ask one more or?

Go ahead Waqar. I'll try to be quicker. I am the problem not you.

In terms of your outlook for crew increases, do you think that they go back proportionally to the different basins and the same kind of proportion as we saw in the previous cycles, or is it more shifting towards just Permian, maybe a little bit going to Bakken, Eagle Ford and DJ?

We started in the Rockies. We have larger market share in the Rockies. But when you have a reset oil prices, lower transportation and differential tend to matter more. So yes, activity will shift. Total industry activity will probably be a little bit more concentrated in Texas than it was. And Liberty's crews or 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. Going forward, you'll probably see more of our crews will be in Texas down the Rockies. We will shrink market share in the Rockies at all. But market share move that will grow market share and Texas will 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 slow shifting following customers and activity level of whether these crews are.

Okay. Chris, thank you very much. This was very helpful and enlightening as always.

Thanks Waqar.

And our next question will come from George O'Leary with TPH & Co. Please go ahead.

Good morning Chris, good morning Michael, good morning Ron. Wondered if you could help frame, it is 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 progress through the second quarter. And then what you're seeing in June and July relative to, either the April or May timeframe? But just trying to get a better sense of that fleet utilization given we don't get much information on that.

Fleet utilization is always lower when things are changing, right. So, in April and May you have fleets that were working that were then shutting down. Those guys are not gone immediately the day you pump the last day that equipment's got to be demoed 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. 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 14th for July 15th start. You've got to get people and stuff 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 wrong term, but some temporary work if it is worth 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 operation. 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 two into a crew running, we should be back to efficient and smooth.

Great, that's helpful. And then just a question born out of curiosity more than anything else. The 97% of the day frac is an incredibly impressive stat based on all the work we've done around how many hours a day you could pump an appreciable spread alert. 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 swapping between well time is just a fascinating stat?

Yes, it is a combination of things. First of all, think of that crew. That's a crew of a bunch of supervisors and guys who were stars and road to leadership. It is a very talent-rich crew. And of course, the goal of 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 a 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 cooperation, 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 is the combination of the humans at Liberty and a great partnership with a highly efficient customer that, since we've started working with it, we've just continually broke their legacy records. I think it is fired them up as much as us up to keep breaking those records.

Thank you for the color, Chris.

Appreciate, George. Take care.

Our next question will come from Sean Meakim with JPMorgan. Please go ahead.

Thanks. Hey, good morning.

Good morning, Sean.

There have been many questions about utilization this morning, which is understandable. Could you provide more insight into how you're managing at these low activity levels and across different fleets to maximize utilization in each basin? There are various challenges in the northern basins compared to the southern ones. I'm interested in how you're planning to achieve sufficient scale in each basin in the second half of the year while also considering how you deploy your fleets to maximize uptime in the current environment.

Sean, it is 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.

Our next question will come from Sean Meakim with JPMorgan. Please go ahead.

Thanks. Hey, good morning.

Good morning, Sean. Sean, it is 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.

So we've begun seeing slightly improving performance in many areas, so that gives us confidence we can make it through these tough times, while we are cautiously optimistic about improvements in volume to come. Now I will turn the call back over to Chris to finish. Thanks Sean.

And our next question will come from Blake Gendron of Wolfe Research. Please go ahead.

Hey, thanks. Good morning, guys. 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?

Price pumping is inherently performance-based since payment is tied to the number of stages completed. We don't charge our fleets on a daily rate, so the duration of our fracturing work directly influences our economics. With some customers, we implement a more significant performance pricing system where a specific number of stages or price applies, and any additional stages are offered at a discounted rate. This approach encourages our partners and customers to increase their speed, allowing us to complete more stages in a day, thereby benefiting both parties financially. Even without this incentive pricing for extra stages, customers still see higher profits and lower costs by finishing their wells more quickly. There are substantial fixed daily costs regardless of the frac spread, and completing a pad 10 to 20 days earlier can save between a quarter to half a million dollars or more while bringing oil to market sooner. This aspect distinguishes our operations from the drilling sector, where the daily charging model limits their ability to capture value despite their impressive advancements. While our own market is somewhat fragmented and we also face challenges in capturing value, we constantly seek ways to better align our incentives with those of our customers. Ultimately, if we can save costs, we want to share those savings, and if we can work faster, we want to benefit together. While there is good alignment, there is always room for improvement regarding economic incentives with our customers. I apologize if my remarks are too broad, but the topic is complex with many variables to consider.

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 add 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 is come early on we had some very different ideas especially in the Bakken that are now widely used that are now normal in the Bakken, but there was resistance to them. And early on we were a brand new company, we did bring the two 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, it is ensured frac designs. But of course they work swimmingly and so after people know they work well, I 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. And we're bringing better ideas and we're making customers wells better. They know technology's 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 is better to be partnered with Liberty. And stickiness matters to us because if we have one customer through a three or four year period, we can just do so much more efficiency-wise, which helps our profitability and our customers' profitability. Then if we've got a different customer each year, even if that fleet’s fully utilized with three different customers over three years. That's not the same value proposition for us as a fleet with the same customer for three years. So we get indirect benefits, but we're not getting a percent of the increased profitability of 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 leased and we want to help them do it.

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 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 the noise of the pandemic and decreasing activity in the Rockies specifically. 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?

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

Cool. Really appreciate the time the answers. Thanks, guys.

Thanks Blake.

Thanks.

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, 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. 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.