Good morning, welcome to the Liberty Oilfield Services third quarter 2019 earnings conference call. All participants will be in listen only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. Please note that this event is being recorded. Some of our comments today may include forward-looking statements reflecting the company's view about future prospects, revenues, expenses, or profits. These matters involve risks and uncertainties that could cause actual results to differ materially from our forward-looking statements. These statements reflect the company's beliefs based on current conditions that are subject to 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 pre-tax return on capital employed, are not a substitute for GAAP measures and may not be comparable to similar measures of other companies. A reconciliation of net income to EBITDA and adjusted EBITDA, and a calculation of pre-tax 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 CEO, Chris Wright. Please go ahead.
Good morning, everyone, and thank you for joining us. We're pleased to discuss with you today our third quarter 2019 results. We're happy to have delivered another solid quarter of operational results in the face of macro headwinds that started to impact Liberty's market midway through the quarter. The year-end slowdown is starting earlier this year. Liberty fully diluted earnings per share in the third quarter of $0.15 were down compared to the $0.32 in the second quarter of 2019. Revenue in the quarter decreased 5% to $515 million, and adjusted EBITDA decreased 24% to $70 million, each as compared to the second quarter of 2019. Strong free cash flow generation for the quarter drove $107 million increase in cash on hand to $140 million at end of Q3.
Available liquidity at quarter end was $344 million. We had a positive net cash position as our cash balance was greater than our long-term debt by $34 million. We were able to deliver this financial performance despite a slowdown in the completions market and an oversupply of frac fleets, both of which resulted in downward pricing pressure. Continued executional excellence of our operations and supply chain teams, plus close coordination with our customers on scheduling enables Liberty to navigate the challenging marketplace while maintaining our ability to drive returns on capital. Central to achieving long-term success are through cycle superior returns on invested capital, maintaining a strong balance sheet and prudently investing for the future. For the 12 months ended September 30, 2019, we achieved pre-tax return on capital employed of 17%, generated significant free cash flow, and returned approximately $75 million to our shareholders.
As always, the Liberty team continues to focus on driving technology innovations and high efficiency operations, which are a win for Liberty and a win for our customers. This cements the strong relationships that we have built with our customers and helps them bring the most cost-effective barrel of production to market. One example of this is our new WellWatch service, which allows real-time pressure sensing in offset wells to monitor impending frac hits. Real-time data monitoring, combined with rigged in pumps on offset wells, helps reduce frac hits in the short term and provides the necessary data to develop optimal strategies for well spacing and frac sizing for efficient pad development and managing parent-child well interactions. Our results for the first nine months of 2019 reflect the strong demand for Liberty's differential frac services.
In the first nine months of 2019, we pumped the same volume of sand that we did throughout the full year of 2018. Total industry frac stages in North America are projected to be up only marginally year-over-year. However, efficiency gains across the industry have raised the number of frac stages completed by each fleet by 10%-20%, which implies a 10% or so decrease in the required active frac fleets. The slowing pace of frac activity in the second half of 2019 is leading to a further reduction of demand for frac fleets, resulting in pricing pressure on services. We expect that the industry slowdown in Q4 completions may be more severe this year than it was last year, as operators face capital constraints and manage completions to fix capital expenditure budgets. This will cause gaps in the completion schedule and negatively affect overall fleet utilization.
Future activity projections in the industry are dependent on multiple factors, including commodity price, availability of capital, and offtake capacity in each basin. Based on visibility into our customers' initial thoughts for the activity pipeline for 2020, we believe demand for Liberty fleets will be strong in the start of the new budget year. We currently have no plans to expand our fleet count. We are seeing reduction in the supply of staff frac fleets in the market, and even announcements of permanent retirements of older equipment. This is helpful, there continues to be an oversupply of frac fleets in the market, which is holding down pricing. We would not expect pricing to improve until supply of actively staffed frac equipment better balances with demand. Liberty has focused on ESG issues from day one. Governance and compensation practices at Liberty have always been focused on transparency and maximizing alignment.
Liberty is also a first mover in driving an environmental and socially conscious approach to hydraulic fracturing. We have partnered with our customers to advance ESG solutions from the start, as demonstrated by our market-leading low-emission quiet fleets. Every Liberty new-built fleet since 2013 has been either able to run on natural gas or is the latest generation Tier 4 clean diesel engine with dramatically reduced emissions. We are in constant dialogue with our customers about how to move the ESG profile of frac operations forward, as such, we are looking to upgrade some existing fleets as part of the normal maintenance cycle in 2020 to Tier 4 DGB dual fuel engines. These units will provide the latest in natural gas-driven power technology available in the oil field. Being a leader in ESG goes beyond emissions, Liberty is focused on leading the industry in all aspects.
These include safe and efficient operations, dust and noise mitigation, traffic management, and environmentally safe fluid systems, to name just a few. The partnerships that we have developed with the communities that we live and work in are unique and provide the necessary insight into how best to provide solutions to specific challenges that our operator partners face. Our DNA drives investment in people, technology, and systems to grow our competitive advantage. We believe that our premium service quality, coupled with basin and customer diversity, provides the company the opportunity to continue generating strong returns on capital employed. Liberty continues to focus on driving technology innovations in both fracture design and operational execution, which are a win for Liberty and a win for our customers.
Our comprehensive analysis efforts on parent-child well relationships with our proprietary database and multivariate analysis techniques has expanded to include the WellWatch field data collection and monitoring efforts mentioned earlier. Liberty's financial results, favorable long-term outlook, and strong balance sheet position us well in today's challenging environment. Liberty is committed to compounding shareholder value by reinvesting cash flow at high rates of return and returning cash to shareholders as appropriate. We are excited by the opportunities in front of us as the shale revolution matures and the benefits that this brings to our industry and the country as a whole. I will now hand the call over to Michael Stock, our CFO, to discuss our financial results.
Good morning, everyone. We're pleased with the performance of our team in the third quarter during what were challenging times for the industry. The Liberty team continues to execute at an unparalleled level that drives customers to want Liberty as their partner. For the third quarter, 2019 revenue decreased 5% to $515 million from $542 million in the second quarter of 2019. Net income after tax decreased 54% to $19 million in the third quarter, compared to $41 million in the second quarter. Fully diluted earnings per share decreased 47% to $0.15 a share in the third quarter, compared to $0.32 in the second quarter of 2019. Third quarter adjusted EBITDA decreased 24% to $70 million from $92 million in the second quarter, and annualized adjusted EBITDA per crew was $12.1 million in the third quarter, compared to $16.1 million in the second quarter.
The major driver in the quarterly decline in EBITDA per fleet was a three percentage point drop in gross margin. The reduction in gross margin was driven by slowing utilization in the second half of the quarter and pricing pressure due to an oversupply of equipment in the market. General and administrative expense totaled $25 million for the quarter, or 5% of revenues, and included non-cash stock-based compensation of $2.4 million. Interest expense and associated fees totaled $3.7 million for the quarter, compared to $3.6 million in the prior quarter. Third quarter income tax expense totaled $4 million, compared to $7.1 million in the second quarter. We ended the quarter with a cash balance of $140 million and a net cash position of $34 million.
At quarter end, we had no borrowings drawn on the ABL facility, and total liquidity, including the $204 million available under that credit facility, was $344 million. Liberty is a returns-focused company, and at the end of the day, sustaining cash flows from investment are what drive returns. Sustaining cash flow per fleet is a metric we use to measure through cycle fleet profitability. We define sustaining cash flow per fleet as the expected annualized adjusted EBITDA per fleet, less our expected annual maintenance CapEx per fleet. During the third quarter, our year-to-date annualized adjusted EBITDA per fleet was $14.5 million. As previously announced, our expected annual maintenance capital for this year is approximately $3 million per fleet.
As we have discussed previously, in order to seek the best long-term returns for our shareholders, we will follow a prudent strategy of maintaining a strong balance sheet, investing in compelling growth opportunities, and returning capital to shareholders where appropriate. In the 3rd quarter, we paid a dividend to our shareholders and distributions to unit holders of $0.05 per share for total dividends and distributions of $5.6 million. Our board of directors announced on October 22nd, 2019, a cash dividend of $0.05 per share of Class A common stock to be paid on December 20th, 2019, to holders of record as of December 6th, 2019. A distribution of $0.05 per unit has also been approved for holders of units in Liberty LLC, which will use the same record on payment date.
As we look forward, we are very positive about how Liberty is positioned to continue its mission to drive best-in-class returns. We're a company that's laser-focused on efficiency and delivering cost-effective solutions and services to our customers. This singular focus and our application of technology to all aspects of our operations empowers us to reduce our cost of delivery in multiple areas, such as unique equipment solutions to provide improved pumping efficiency and reduce the cost of repairs and maintenance, significant operational fuel savings due to our ability to burn natural gas. Close customer coordination, combined with advanced logistics management, enable us to more accurately forecast sand requirements and optimize logistics. This allows us to work with our partners to deliver the lowest cost of sand to the well site for our clients. Liberty's innovation powers our ability to deliver industry-leading returns.
With that, I'll turn the call back to Chris before we open for Q&A.
While the market is currently oversupplied with frac capacity, positive trends are emerging. Many of our competitors have idled significant capacity and announced permanent disposal of older frac equipment. Both of these trends are necessary for the frac market to balance. The biggest driver of the current oversupply of frac capacity has been increased efficiency of active frac fleets. Liberty has been a leader in efficiency. Less efficient fleets and crews are being driven from the marketplace. The U.S. rig count has declined roughly 20% over the last year. Not surprisingly, the rate of growth in U.S. oil production has also declined significantly. With this trend, we may see U.S. oil production plateau in early 2020, which could help tighten oil markets and provide upward bias on oil prices.
While timing is uncertain, we appear to be making progress towards a healthier U.S. oil and gas industry as supplier frac fleets and oil are both facing significant downward pressure. As I said last quarter, the cure is twofold: more disciplined investing and time. Liberty was built from day one not only to survive the tough times, but to take advantage of the inevitable market cycles. During the tough 2015-2016 downturn, Liberty significantly grew our market share, took advantage of market dislocations to grow our capacity, and deepened our customer and supplier relationships. These actions played to our advantage during the subsequent recovery. In short, market cycles can present unique opportunities as well as challenges. I'll now open it up for Q&A.
We will now begin the question and answer session. To ask a question, you may press star then one on your touch-tone phone. If at any time your question has been addressed and you would like to withdraw your question, please press star then two. This question is from John Daniel with Simmons Energy. Please go ahead.
Hey, guys. Chris, Ron, just want to dig into the Tier 4 DGB comment you made earlier about adding more, basically doing engine conversion. Can you quantify for us how many fleets might be outfitted with these engines? Secondly, will you convert Tier 4 DGB to Tier 4 DGB or Tier 4 to Tier 4 DGB?
John, there's trade-offs in all of those. The short answer is it all depends on circumstances. I'd say we'll convert at least one fleet. Could be one or two more than that. It depends on market, it depends on demand. The actual which do you transition to which depends on the circumstances. All very likely what we'll be converting to Tier 4 DGB will be older Tier 4 DGB.
Okay. Got it. Is it possible to get some color on effective utilization of the fleets in Q3 and Q2? I know the active was 23, but how do you look at the effective utilization?
I would say through Q2, it was quite solid. There's always schedule changes and slips, so there's an inevitable certain amount of white space. We're not guys who sort of take theoretical limits and then come lower numbers from there. I would say it was quite strong through most of Q3 as well, and then starting to struggle later in the quarter with full utilization.
Okay. Got it. I'll keep it to two and jump back in.
Thanks, John.
Thanks, John.
The next question is from Sean Meakim with J.P. Morgan. Please go ahead.
Thank you. Good morning.
Morning.
Morning, Sean.
Hey, Chris, to your point in your opening remarks, efficiencies are creating phantom capacity within the active frac fleets. Looking forward, how much room is there to run? I suppose specifically in the Permian, where there seems to be the most still opportunity for service efficiency, how much more of that cycle do you see out there?
I would say we're definitely coming into a period of diminishing returns. The low-hanging fruit, frankly, the stuff people should've been doing years ago, most of that is gone. I think growth and efficiency from here going forward is certainly at a significantly slower rate than it's been in the past few years. We've had a huge run up in that. We pushed out a lot of the older, less competent fleets. That in itself, with no operational changes, raises the average efficiency of frac fleets. Now you've got a leaner number of fleets running that are higher quality. You've got customers that are almost across the board now more focused on efficiency and throughput. I would say our throughput in the Permian has been outstanding. In fact, it's probably the highest of any basin we have today. Look, we're always going to strive to get better.
I think you'll see Liberty get a little better, but I don't think you'll see the huge increases in average frac efficiency the next two years that you've seen in the last two years.
Thank you for that, I think that makes a lot of sense. Then just curious how much confidence you have in the strong demand comment in the release for 1Q20. Is that in comparison to 1Q19? Is this just a relative comment compared to what may be a worse exit of 4Q19? Just how should we think about operating leverage, and the influence on EBITDA per crew in the next couple of quarters here?
With a comment of strong demand in Q1 2020, that's based on where we are today, based on Q4, where we have a significant slowdown at the end of this year, just as we did last year. We don't think that's the new normal. We think we'll be meaningfully busier in Q1 than we are in the current quarter. The marketplace is tough. Our goal is to keep our relationships with our customer alive, strengthen, and grow market share. As we see opportunities for the right customers we want to add to keep all the fleets busy in a softening market.
Yeah, Sean, I think what we're seeing here is I think you're going to see utilization pick up of order the same way that it did last year. It's been definitely a soft. We've got some different budget exhaustion that everybody's fighting. A little bit of capital constraints as well on the private side. That's also causing a problem for Q4. I think you're going to see the same utilization pick up. I think the wild card at the moment is probably what is the price? Price at the moment is something that is sort of under negotiation, and that's really dependent on how much supply leaves the market, where the market dynamics roll out through this pricing negotiation phase during Q4 for all the clients. Hopefully we'll see just across the industry, we're not seeing too much looseness at the moment.
We shall see where that ends up. Yeah, as far as activity, I think we're going to see a very similar drop in activity in Q4 from Q3, like last year, maybe a little bit more. I think we'll probably see the same pickup in activity Q1 next year by the looks of it from Q4. The only question there is what's the relative price points for that when you're coming into the earnings side?
Thank you for that. One last piece to it, if I could, is just, is there a scenario next year in which you see yourself stacking fleets?
I think it's unlikely, Sean. I'd say it's unlikely. Our goal in soft markets and downturn is to grow market share, build our customer relationships, and get better at what we do. We don't control the macro pricing of the marketplace, and we take a full through-cycle view of our earnings, our return on capital, and hence we follow a meaningfully different downturn strategy than the marketplace as a whole. I wouldn't expect that to change here.
Very helpful. Thanks a lot.
You bet, Sean.
Next question is from Blake Gendron with Wolfe Research. Please go ahead.
Hey, thanks. Good morning. Just want to follow up on your comments about capital allocation and downturn. Where do buybacks now compete in terms of returns? Just given the visibility that you have in a free cash flow next year, outside of perhaps the seasonality that we're gonna expect over the coming years in the back half, do buybacks make sense, just given that we're in a retrenchment wait and see mode for E&P spending next year?
Yeah, I think you added in the right qualifier there at the end. On a valuation perspective, buybacks look highly attractive right now. We're in a mode right now where it's not unclear exactly how this cycle unfolds. In the face of significant uncertainty, usually better to err on the cautious side.
Okay, that makes sense. You've been a pretty vocal consolidator in the past, and you made comments recently about the availability of horsepower in the market now. I'm just wondering, we've heard from your peers about scrapping and disposing of equipment. I would imagine a lot of horsepower has come to market. When you evaluate that horsepower, can you give us an idea of how much is viable, either from a Tier 4 perspective or dual fuel perspective, and then also too, given the intensity that we're seeing across all of the major shale basins?
Well, I would say we have a significantly higher than the industry as a whole proportion of dual fuel, probably the highest. Our Tier 4 percentage is pretty high as well, pretty much everything we look at is meaningfully lower on those two spectrums. You've got to look at what's the total value of the equipment going forward. That's a different profile for different asset sets. You're right, there's a lot of equipment out there. We engage. We look at most everything that potentially has appeal. It takes unique circumstances, and maybe we're getting close to those, for things to make sense. Yeah, it's not a single number. It's the whole package, the whole how it fits in a future and what makes sense or what doesn't.
Okay. Thanks for taking my questions.
Thanks, Blake.
The next question is from David Anderson with Barclays. Please go ahead.
Hey, good morning, Chris. You had talked about in your comments just a few minutes ago about kind of managing through the cycles and kind of your approach to this. The second year in a row now, we're seeing kind of a big change from first half to second half in terms of spending from the E&Ps. Looks like we're going to see that again next year. Two years, it really seem to be making a trend here. How has that changed sort of your approach as you think about the market, and how do you kind of smooth this out? Is there any way to sort of smooth out this kind of, which seems to be kind of crazy spending pattern, which we're seeing out of the E&Ps?
It's a great question. We have yet to get different incentives set for E&Ps, right? If you're going to spend a smaller amount of budget and you're going to be rewarded on production growth, it's just logical to front load your spending a little bit. You're right, that causes dislocations later in the year that the industry has not historically had, or certainly not had to the degree we have today. I think with time, you'll see some offsetting factors. There's still a large amount of activity that's among the privates, right? If you're a private company, I think if you see this as a pattern, I'm going to do the opposite. I'm going to backload my activity because equipment's available then. It's easier to get on schedules. I think you'll see some offset there.
You've also got the majors that are not a giant part of spending right now, but they're growing rapidly. They're going to become a larger % of the total development CapEx. They don't have the same mentality. They have a balance sheet and a size and a scale that has led to flatter, more constant activity levels. I think they also recognize the efficiency and safety benefits for running continuous operations. I would say, I think everyone recognizes that, but there's a suite of companies and sort of midsize or smaller publics that know that's true, that have historically done that, but are struggling with it right now. Some of that probably becomes to a little bit better with time, but I think there is a basic challenge there.
You've got majors and privates that I think, after the industry has another year or two to adapt to this, I think probably mitigates the magnitude of the dislocation we saw last year and that we're seeing this year.
Great, thanks. Interesting answer. You're no stranger to the regulatory environment, that's for sure, being out there in Colorado. A lot of talk, of course, lately about potential change of administration, what could happen. Certain woman out there says she wants to ban fracking and kind of looking at federal lands. Can you just talk about your exposure to customers on working on federal lands? Maybe how do you think this could potentially play out over the next kind of 12 months? Do you think things start moving around? Are operators kind of even thinking about that yet, or is it too premature?
Well, everybody considers, certainly our customers consider what could happen, what wild cards are out there. Certainly that is one of them, I would say, actively considered. The places with meaningful federal lands is the Powder River Basin, in the New Mexico part of the Delaware. Fortunately, certainly in the Delaware and in the vast majority of the shale basins, they're dominantly on private land. They're federal lands. They're not trivial in scope, but there's nowhere they're a large part of activity except in the Powder River Basin. Even the Powder, of course, has tons of private and state land. Then there's large long-term plans, these federal units that get created. Certainly it would be a negative, certainly it would be a sentiment problem, and certainly planning would have to evolve around that.
If we saw a meaningful change on federal lands, I think that takes some time to come in, and people will shift their activity onto non-federal lands. It opens up a big battle, but does it cause a collapse in industry activity soon after election? I think that's highly unlikely.
It'll certainly cause dislocation, but I guess what you're saying, you think it'll settle out. I was just curious, are you seeing any of your customers kind of already making?
changes to their plans yet?
I think, I don't know, probably no one's changing which locations they're going to drill today, I would say many are considering, if this happens, how do we pivot? You'd get more federal permits now. You'd have a buffer. You'd have a plan that if that's been dried up, I've got to have an ability to keep my capital expenditures and my rigs running in my other areas. I think it would be very little that could not navigate that. It would be a negative. It would put locations on long-term hold and all that, but I don't think it would be massive disruption to most people's, to anyone's plans.
All right. They're coming up with a plan B. All right. Thanks, Chris, appreciate it.
Yep, you bet.
Next question is from Chris Lloyd with Wells Fargo. Please go ahead.
Good morning, guys.
Good morning.
Just curious. It sounds like 3Q utilization was kind of decent, a little bit weaker at the end, but not that bad. EBITDA per fleet came out at about $12 million. GP per fleet probably $16 million-$16.5 million. If you think about the pricing environment that you got right now for work starting in 2020, can you give a sense of where EBITDA per fleet might shake out? I imagine, it's going to be somewhat lower, and maybe you get a rebound in utilization that'll take it a bit higher. If utilization was similar to 3Q and pricing kind of landed where discussions are currently, how much lower would EBITDA per fleet likely be?
Yeah, Chris, I think, this is something that we'll probably comment on as we get towards the beginning of next year, as we get through these discussions. I think there's still a lot of moving parts as far as pricing goes. I think you're right. We've been in a relatively negative price environment as we've sort of moved through this year. There's a bit of a downward pressure on pricing all the way through Q3. What you're seeing in Q4 is, as we've had sort of budget exhaustion, you're refilling some of your utilization of things, and you're refilling some of the utilization with work for folks that is not a particularly great pricing. That's sort of just the fact that it's a fill-up, and you're sort of doing some work with them.
That pricing will rebound a little bit maybe into Q1, but we'll have to see. There's a lot of moving parts at the moment. There's probably ongoing discussions on by far and away the majority of the fleet's going on at the moment.
Okay. Then in terms of the 24 fleet, your previous commentary around that was that you wanted to hold it off the market until pricing improved. It seems like the odds of that taking place, and especially pricing that would've been higher than the first half of 2019, it's hard to picture that in the foreseeable future. Are you likely to put that fleet to work now in 2020?
We can't talk about 2020 in total, but yeah, if you look at the general market conditions, no. The more likely than not at the start of last year, if you'd asked us four months ago, more likely that it was going to be starting in January. I think where currently the market is, the more likely event is that we'll start next year with running 23, as 23 staff fleets and just leave it at that. We'll see as we go. There could be, as we have discussions with some key clients and some potential new clients, if we've got demand from somebody who we've been wanting to work for a long period of time, and they need some expansion capacity, we could bring that to market. That's a long-term pricing discussion we'd have with that client.
Okay. If I could just squeeze one more quick one in.
Of course.
It seems like the industry might drop, based on companies that have reported thus far, up to 15% of fleets, maybe 10-15 in 4Q, which means there'll probably be a decent rebound in 1Q. Is there a set of your customer base that you'd potentially like to upgrade by poaching work from incumbents that have had fleets go down? Are you, in general, think you have the optimal customer base currently?
No, there's always room for improvement. When the whole pie shrinks, then that means there's market share to be taken. No, we're always thinking about things like that. We're talking about things like that. That's why. It's not what's the best today, but where do you want to be? How do you want to position yourself through the whole cycle? At the bottom of the 2016 cycle, we were aggressively putting out fleets into what was then bad economics. We were looking ahead to what was coming down the road, not what today was. Today, it's nowhere near like the bottom of 2016 where we got a clear view of where we are. I'm not saying we're there now, but it's always a collection of things. Current pricing is one of those things. There's other trade-offs as well.
Right now, I think you will see Liberty be pretty cautious. We're not gonna grow our fleet, and we're not gonna build new fleets. We're not gonna expand meaningfully from where we are today in the current crystal ball we have.
Okay. Thank you.
You bet, Chris. Thanks.
Next question is from George O'Leary with Tudor, Pickering, Holt & Co. Please go ahead.
Morning, Chris. Morning, Michael.
Morning, George.
You guys are always kind of on top of leading edge completion trends and changes in well design. Of late, we've started to hear, and these are not necessarily new, but just hearing increasing chatter around more folks looking at using them or revisiting using them once again. Heard a little bit more about kind of monoline frac jobs, whereby you reduce the number of connections associated with the iron on the frac jobs, and then two, some folks revisiting using simul-fracs, and Chris, I know you're very familiar with that one. Are you guys seeing either of those items crop up more? Two, anything else notable on the just well design or completion change that you guys are seeing E&Ps try to push?
Morning, George. This is Ron. Yeah, I'll take the monoline question. Then I'll let Chris maybe throw in some thoughts about simul-frac. Certainly, the monoline idea is something we've been focused on for a little while now. We started down that road earlier this year. I think we see that as a good innovation going forward, we'd love to see more of on our locations. I think when you look at the R&M cost of a frac fleet, treating iron is no small part of that. There is also a significant HSE piece to that as well. Reducing number of connections and things like that are all things that we like to look at. Certainly, when you think about efficiency, our ability to continue to find ways to spend more minutes pumping every day, we see this as an opportunity to improve there as well.
Yeah, certainly expect to see from Liberty continued focus on deployment of monoline in the field. We're still working through exactly what that solution's going to look like for us. We've tried a number of different scenarios there, but I think we feel that that together with a system for interfacing with the wellheads, together with the wireline guys, is gonna be the right solution going forward.
Yes. Yeah, some exciting stuff there. Also on simul-fracs. You're right, we have a long history in that area, and there is stuff going on today, in fact, as we speak, on that as well. When you're developing pads and frac interaction or frac growth patterns are central, that is definitely one of the tools to impact frac interactions. We've even done a very different kind of simul-frac, but I don't think we've talked about publicly, and probably get confirmation with a customer before we'll elaborate more on that. Yes, customers in the world today are definitely very innovative. We're always bouncing ideas back and forth about what might be a next step forward. Technology, how do we more optimize the plumbing underground to develop the resources we've got? It's a fun area, but you're right, George.
There's still a lot going on in that area, and I'm sure you'll hear more about that as time goes on.
Okay, great. Thanks very much for the color, Ron and Chris. Maybe just one numbers question from me. As you think about CapEx in 2020, it seems, given all the comments you guys have provided, that something closer to maintenance CapEx than what you spent the last few years is a reasonable way to think about it. There are still some growth initiatives or fleet upgrade initiatives, as you mentioned, with the DGB Tier 4 engines. Just not wanting to get out over my skis here is $100 million in CapEx for the 2020 timeframe a decent placeholder to have in our models for now, or should we be thinking about that differently?
No, George, we're probably okay with talking about that. As we said this year, we probably average around about $3 million of fleet and maintenance CapEx, and we're always working on ideas to try and drive that lower, kind of with long-term design. We also do, as you said, investing for the future, investing in whether it's monolines or the quick connects or the DGB upgrades. Yeah, sort of in that range of somewhere between $3 million of fleet maintenance CapEx and that $100 million which we spent, which when we announced this year, which was maintenance CapEx plus technology investments, is probably a good range of baseline unless we see the market change.
Great. Thanks for the color, Michael and guys.
Thank you. Thanks.
The next question is from Chase Mulvehill with Bank of America. Please go ahead.
Chase, you might be on mute. We're still not hearing you. I don't know if you've dropped off or if you're on mute.
Frances, you can move to the next question if you like, and then Chase can call back in if need be.
The next question is from Waqar Syed of AltaCorp Capital. Please go ahead.
Hey, good morning. Thanks for taking my call. Could you help us with the stages per quarter that you did in the third quarter? How does that compare with the second quarter?
Waqar, as you know, we don't release stage numbers just because I think we find it gets a little confusing out there in the world. Stage sizes and lengths different. You can go anything from a one-hour pump stage to a four-hour pump stage. Just to say, I would say, general activity was of order flat to just probably just slightly lower. As we said, Q2 was a very, very efficient quarter. As we guided to at the end of Q2, I think with that slowdown at the back end, we were just slightly lower on activity in Q3 than we were Q4.
Fair enough. In terms of the EBITDA per crew, when we looking at the first quarter of next year, is it going to look similar to the third quarter of this year, you think? Can it do better or worse than that?
Waqar, I think probably you'll see activity levels probably similar Q3 to Q1. You've obviously got the winter slope. It's a little harsher in winter. I'd say in general, we had the slowdown at the back end of Q3.
Actual hours pumped could be fairly similar Q1 to Q3. The wildcard there is just, where on average pricing is.
Okay. How much pricing so far in the fourth quarter, what you know about in the fourth quarter is below the third-quarter levels?
Yes. Obviously there is pricing pressure, as we've seen because of the oversupply of frac fleets. Again, Q4 is a tough one for people to look at because you've got budget exhaustion for your long-term clients. As we discussed at the Barclays conference, we had some issues on a couple of clients who just ran into a surprise on takeaway issues, which meant we had to move a couple of fleets, and at least one of them is starting back up in December. A lot of the work that you're filling in therefore is a different pricing flavor, much lower than your fully utilized fleets. It's like apples and pears as far as comparing those two quarters as far as average pricing goes.
Okay. Thanks very much. That's all.
Thanks, Waqar.
Next question is from Chase Mulvehill with Bank of America. Please go ahead.
Hey, can you all hear me now?
Yeah, we can, Chase.
Chase, we're giving you a hole again. You can't take those in tournaments or in competitions, you get a hole again.
Yeah. Sorry, I had to dial back in. I don't know what happened. I guess, if we think about 4Q, can you maybe just help better frame 4Q? You said that sequentially it'll be worse than the fourth quarter of last year. Do you think it'll be twice as bad when we think about a sequential decline? Just help us understand from a top-line perspective what it means, and then, from a profitability, how bad do you think it could get?
Chase, this is Michael. Yeah, I think I commented in our prepared remarks. Really was nothing, the whole industry turned down will be worse. It could be slightly worse Q4 than Q3. I think you're right. Our order, it could be similar for us. Last time we were down from Q3 to Q4, about 15 points on the top line. You've got a little bit of change there as we've moved to more self-source sands, that could be a little higher. On the EBITDA, it was down 40%, just quarter-over-quarter, and then rebounded in Q1. If you're using that as a guidepost, it's not a bad guidepost.
Okay. All right. I guess maybe if I just try to dial in a little bit on the EBITDA per crew, if we just look at 3Q. The release talked about the first half being pretty good and things tapering off in the back half. If you were to look at profitability or EBITDA per crew in the back half, if I do some math, it looks like maybe it was about $8 million of annualized EBITDA. Is that the right number, and is that how we should be framing things as we get into the fourth quarter?
Yeah. It's really not something we don't discuss. Everything moves about. I think we've done prepared remarks before. I think if we go back a year or so, when we try to talk to the world about our $28 million of fleet that we earn at the high point. It can vary quarter to quarter, right? One, it can be total demand that goes off, or it can just be operational issues, right? You can have a number of times when everything goes right and everything goes wrong. Even on a quarterly basis, is not honestly the way we look at results very much. We really like to look at them on a longer period of time than that. Yeah, just a long way of saying we wouldn't discuss inter-quarter results.
Okay. All right. Understood. I guess coming back to questions around DGB fleets. I may have missed it, I dropped off. Did you talk about the cost that it is to convert a Tier 2 engine to a Tier 4 DGB? maybe, the visibility that you have to put the one to two fleets back to work, and maybe the paybacks.
Right. Really, a DGB Tier 4 engine, compared to a brand-new non-DGB engine, is not a major uptick in price. It's probably just a bit over 10% more than a standard engine. What happens is, part of the normal maintenance cycle, you have a number of fleets coming up to their 25,000 hours that they've run on those engines. We always bring those fleets in and look at them proactively. Now, if that engine is in relatively good shape and it's got a relatively low rebuild cost on it, that particular pump may go back out as it's going to get rebuilt and go back out as a Tier 2.
If it's got a cracked block and it's got a significant rebuild cost, now you're talking about something that was maybe a $350,000 rebuild that now becomes just north of $500,000 rebuild on that engine side of it. Then you'll upgrade it to Tier 4 DGB. It'll actually happen on a pump-by-pump basis. I think the difference with Liberty and a lot of companies is, to some degree, the unique fact that all of our equipment is plug and play, right? Everything works the same. It's generally got the same line up. If we rebuild a specific pump that was Tier 2 with Tier 4 DGB, it can roll into a Tier 4 DGB fleet just as easily as the one that was getting rebuilt as a Tier 2 rolls back into a Tier 2 fleet, or you can mix and match.
Okay. Did you weigh electric fleet versus converting to Tier 4 DGB?
Yeah, Chase, this is Ron. We certainly have weighed that and certainly are headed down both roads. I think as we've already said, now we have a development initiative going on the e-fleet side of things. We've also had a significant focus on understanding the pros and cons of both of these scenarios. We've been out on the road probably the last four weeks now, helping E&P companies to understand exactly what the benefits of an e-fleet versus a Tier 4 DGB fleet might be and what the trade-offs are there.
I think there were some misconceptions out there around the emissions profile for those engines, and I think we've been helping folks to understand that we can deliver a very compelling solution with Tier 4 DGB that has a lower greenhouse gas emissions footprint than an e-fleet would have under standard operating conditions in the places we work. That can offer fuel savings that are in line with, or in many cases, potentially even better than, at a significantly lower capital cost up front. I think what we're going to find is that we're going to have customers who maybe had thought that they only had one option in front of them, now have two very viable options in front of them, Tier 4 DGB or e-fleets. I think you'll ultimately see both of those in Liberty's world.
Rate of deployment probably looks different for each of those technologies. Tier 4 DGB obviously coming first and fastest. There is still work going on in our world on e-fleets, and there's a reasonable possibility that sometime down the road, there will be an opportunity that is the right fit for that technology as well.
Okay, perfect. I appreciate the color. I'll turn it back over.
Thanks, Chase.
Next question is from Stephen Gengaro with Stifel. Please go ahead.
Thanks. Good morning, gentlemen.
Good morning.
You've covered a lot. I wanted to just get your views on this. Clearly there's been a couple of announcements of fleets being retired, and one of your competitors, I think, noted that their equipment out there was sort of serviceable, but the maintenance costs have become onerous, and it was just basically hard to operate them profitably. When you look at the industry fleet, and you sort of think about your positioning there, what are your expectations for fleet attrition and how the industry fleet kind of bleeds down over the next maybe 12 months, given what looks like severe under-investment right now?
Predictions are hard, particularly about the future. If you look at just the straight math and straight logic, it actually looks pretty encouraging that a lot of fleets will leave the market in the next 12 to 24 months. It depends on market conditions, right? I think you hit the point that if you've got a lousy fleet, but the market's super strong, they put the band-aids on and spend the money and keep it running. If you're going to leave a basin, it's the last fleet you got going, and you fight to keep the last man standing, people will do stuff that's maybe not economically rational, but they've got other reasons for it.
I do think a softer market that we're in and going into, we actually think it could be a real positive for the marketplace because that tends to get people it causes some stress, and it tends to get more rational economic decisions. I would say our guess is we'll see a relatively large amount of capacity out of the market 12 months from now, permanently. A fair amount pushed out. There's an upgrade cycle that's new capital and frankly, new technology and new systems. I think we're going to see a meaningful transformation of the frac marketplace and the players in the space, I would suspect, over the next 12-24 months. That's a prediction. It's purposely vague, I won't be as wrong as I could have been.
Yeah, we're having enough trouble with the fourth quarter, right? To try to figure out the next 12 months. Just as a quick follow-up on that, you mentioned your kind of three million per year of maintenance CapEx. Should that number be pretty sticky over the next year or two?
Say again, Stephen, sorry.
Your maintenance CapEx per fleet, are you seeing that trend higher at all, or do you think it remains around $3 million? I know you referenced 2020, but as we go forward here, do you think that number remains right around $3 million per fleet?
Stephen, I think it probably remains in that zip code, right? I think maybe it'll tick up five or 10% as we move forward with some technology upgrades. You can put it into the technology upgrade or maintenance CapEx budget. If we're getting the same, I think that zip code is about right. That's what we think is the long-term cost.
Very good. Thank you, gentlemen.
Thank you.
Next question is from Thomas Curran with B. Riley FBR. Please go ahead.
Good morning, guys.
Morning, Thomas. How you doing?
Good. Chris, as part of their just-announced fleet rationalization, one of your competitors revealed that they'll no longer have a presence in the Bakken. Have you already started to see an opportunity arise from their withdrawal, or would you expect to?
Different players have different customer bases. On the margin, it's a positive in the marketplace to see a little capacity leave in a basin. Bakken's our original basin. We've been there a long time. We know the players in the basin. It's been a good basin for us. I'd say we have a very good competitive position there.
On the margin, maybe a slight positive, but we're not going to change our strategy or customer targeting or anything like that.
Right. It's in part because of your deep legacy roots there. I was curious. Ron, what % of your jobs in 3Q involved frac onomics, and how did that compare to 2Q and 3Q of last year?
I'd say year-over-year, it remains relatively flat. I think from our standpoint, we probably provide some level of engineering service for economics, et cetera, to maybe 75%-80% of our customers. It varies in that world from maybe we're providing a second set of eyes on work that they have done internally and would like us to review, to, at the other extreme, we are providing the complete engineering package and the design from the ground up for them.
Just in this ruthlessly Darwinian environment of the past several months, which of your technology offerings, if any, has conveyed the greatest competitive advantage? When you're out there in actual hand-to-hand combat, bid by bid, which is consistently emerging as the real differentiator?
Well, I think we probably take the approach that any technology that ultimately led to an improvement in efficiency for us on location are the ones that have played the biggest role. That's a bundle of technologies for sure. I think those are the ones that continue to assist in Liberty proving our differentiation relative to our peers.
I'd say WellWatch has got a lot of interest. It's a recently rolled out thing, but this is more of a long-term thing. If you want to understand how to develop the well spacing and frac size and the optimal interaction between fracs, both the Liberty engineering efforts there, which customers are doing themselves as well, but now to have a technology to measure in real time how fractures approach other wells and what you might do to mitigate that, there's a lot of interest. That's got off to a strong start.
Helpful. Thanks for taking my questions.
You bet. Thank you, Thomas.
The next question is a follow-up from John Daniel with the Simmons Energy. Please go ahead.
Thank you for putting me back in.
Thanks, John.
Just a few quick ones here. Ron, you noted you're looking at the dual path of electric versus Tier 4. Can you say if you guys have leased or bought any turbines yet? If so, how many and what type of turbine you would use?
I can say we have not leased or bought any turbines yet, John. That's certainly a part of this that we are still working to understand is exactly how that piece of the world would play out for us. Right now, we're focused on the technology specific to the pump and then ultimately the backside. We're thinking in parallel about what the power supply is going to look like there. Obviously, a lot of questions around that. From the work we've done in terms of understanding emissions profile, what the demand requirements are going to look like on a pad on a day-by-day basis and over a year of operations, we've come to understand there are some important variables we want to think about in terms of selecting a power supply, and then, of course, ensuring that doesn't ultimately affect our efficiency that we've become known for.
Lots of work going on there, but no firm decisions in that space at this point in time.
John, one thing that really changes the relative trade-offs on frac fleet technology is if you can run off line power. I don't think that's going to be widely available to the industry, but I think you're going to see places where we see large power electrification. If you can run off line power, the advantages of electric frac fleets are very strong. If they're run as they are today, as Ron said, in many areas, they're weaker, and some maybe they're a little better. It's kind of a preference thing. In areas that get line power, electric frac fleets make a ton of sense. We're excited about that opportunity and idea. We think in some areas we will be seeing that.
Okay. Big picture question for you, Chris. We're all somewhat hopeful about majors, mega cap E&Ps plans to continue their growth initiatives. I think we're all hoping that that growth contributes to an eventual rebalancing of the market. I'm just curious, are you at all concerned that these same companies haven't yet figured out the completion efficiency gains, as say the independents, thus we might be overstating somewhat the impact of their growth plans, if that makes any sense, as they get up the learning curve?
It's different strengths and weaknesses. There's enormous technology base in these companies. They're incredibly safe. They may be more judicious in their movements, but we work with one of the majors right now who's very efficient and way down that curve. The others maybe that are more cautious approach to getting there's no reason they can't and won't get there. Yeah, it is a different profile. It is a different speed of changing the way things are done. They're very strong companies with super high quality people. I think years down the road, I think they will be a much larger percent of what's going on in unconventional, and I think their performance will be awesome.
Okay. Last one, just to follow up on fleet attrition, because no one's really elected to put you on the spot, so I guess I'll be that guy. When will Liberty see its first fleets get permanently retired?
Good question. It's a gray zone there. You may see our oldest fleets and lower technologies be so upgraded that they may not look a ton like they were originally. You could call that retired or significantly rebuilt.
Yeah. The majority of our fleets, John, were built post the, sort of like from the beginning of time, we worked at sort of 24 hours a day, 10,000 PSI, two-mile vertical, sort of horizontal laterals, right? The majority of our fleets have really been designed for that sort of work. If you think about the rig, this stuff was designed from 2011 onwards. We were on the back end of our first couple of fleets that were on the end of that spectrum where people were trying to lighten up pump equipment to try and make it not a permitted load, right? There are shorter trailers, you had the Allison Transmission, et cetera. I think you've got maybe a couple of fleets there that'll have to get, sort of like as they move forward, may get a pretty significant overhaul.
The rest of them, really, we sort of moved very early to a Cat, Cat, and really, I don't see that really changing. You upgrade to a Tier 4, you've got to upgrade the radiator package. The rest of the place really stays the same. We're a little different. We're a little luckier in the time that we entered the market. We entered at the right time, for the fact that we haven't got a real major change in the way the work happens.
Okay. Fair enough. Thank you for your time.
Thank you, John.
Thanks, John. I want to sincerely thank the passionate, wonderful folks on Team Liberty that make it happen every hour of every day. I'm proud to be your partner. Safety is the top of the list for all of us every single day. I also wish to thank our customers, suppliers, and investors who make it all possible. We look forward to talking with you in three months.
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