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Liberty Oilfield Services Inc
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Good morning, and welcome to the Liberty Oilfield Services First Quarter 2018 Earnings Conference Call. [Operator Instructions] 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, include -- 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 our companies. A reconciliation of net income-to-EBITDA and adjusted EBITDA and the calculation of pretax return on capital employed, as discussed on this call, are presented in the company's earnings release, which is available on its website.
I would now like to turn the conference over to Liberty's CEO, Chris Wright. Please go ahead, sir.
Good morning, everyone, and thank you for joining us. I would like to take a moment to thank our entire team for going above and beyond during the quarter. We encountered significant operational challenges arising from unusual winter weather and sand logistics issues. However, our team came together to deliver record revenue and adjusted EBITDA.
In the first quarter, our revenue was $495 million and net income was $54 million. Adjusted EBITDA for the quarter was $100 million or $20.4 million per average active frac fleet on an annualized basis.
We are our returns-driven, organic growth company. We aim to compound shareholder value by reinvesting cash flow at high rates of return, in combination with returning cash to our shareholders as appropriate.
Our trailing 12-month pretax return on capital employed grew to 39%, up from 35% for the full year 2017.
The first quarter presented operational challenges. In January and February, we experienced unusual winter weather across all 5 of our operating basins, reducing throughput and in some cases, temporarily shutting down operations. There were also significant industry-wide sand logistic challenges caused by rail interruptions. But due to our deep relationships with our sand suppliers and deft execution from our dedicated supply chain and logistics team, we successfully navigated these challenges without any fleet downtime due to waiting on sand.
Despite these challenges, we generated average annualized adjusted EBITDA in excess of $20 million per fleet across the organization.
Throughput and profitability returned to the levels we expected to see by March, and the second quarter is off to an excellent start. We are excited with what we see for the remainder of 2018. The frac market remains strong, and we continue to drive increases in throughput across our entire fleet.
With winter in the rearview mirror, our customer challenges water supply, wireline and wellheads have returned to normal. All of our customers are working in tandem with us to get more done every day via improved procedures, coordination, systems and equipment.
In the current quarter, we expect to surpass our adjusted EBITDA per fleet metrics from last year's Q3.
In the Permian, we are pleased with our deepening customer relationships and the results we are seeing. During the first quarter, we deployed our sixth Permian fleet under a dedicated arrangement. The Permian market remains very tight for top-tier high-efficiency frac fleets, and pricing is strong. More importantly, we are seeing meaningful throughput and efficiency gains across our fleets in the basin. We believe that throughput and efficiency, more so than price, will continue to increase profitability in the Permian over the course of 2018.
We began operations in the Eagle Ford at the end of the third quarter 2017. A new basin typically ramps up to full efficiency over a period of 6 to 12 months, as we train and libertize our crews, enhance logistics and find the right partners who share our same passion for throughput and efficiency. We are pleased that entering the current quarter, both Eagle Ford fleets are working on a dedicated basis, one with multiple customers, and have begun to hit their stride.
Our focus on equipment design and technology-driven predictive maintenance with the goal of achieving lowest total cost of ownership, continued to pay dividends in the first quarter. We averaged less than 5% of our equipment down at any time, that's less than 1 pump per fleet. In fact, our original and oldest fleet, which is just coming up on its first major rebuild cycle, achieved a record 2.1 days of continuous pumping time in March, almost 3,000 minutes and 29 frac stages of nonstop pumping on a ball-and-sleeve completion in the Bakken.
The last year has seen major improvements in the oil markets supply and demand balance. U.S. oil inventories are more than 100 million barrels lower than they were just one year ago, and the oil prices reflect this move towards normalization. The U.S. will be the major incremental supplier of this year's projected, robust, worldwide demand growth of roughly 1.5 [ million ] barrels of oil per day. Our customers are driving this oil production growth, predominantly out of cash flow. The market is strong.
The closely related market for frac fleets is also robust, although there appears to be somewhat different market conditions for Tier 1 frac crews versus Tier 2 or Tier 3 crews. The, "I have got to get a frac crew" market appears to have loosened a bit, where the, "I need a reliable Tier 1 partner" market remains tight.
We still field far more intriguing requests for Liberty fleets then we can satisfy. Our capital deployment plans for 2018 remain unchanged. For the first quarter, we averaged 20 active frac fleets. As previously announced, we deployed our 20th and 21st fleets during the first quarter under dedicated arrangements with existing customers. We have staffed our 22nd fleet and remain on track to deploy that fleet at the end of the second quarter. We anticipate the deployment of our 23rd and 24th fleets at the end of the third and fourth quarters, respectively.
I will now hand the call over to Michael Stock, our CFO, to discuss our financial results.
Good morning. We are pleased with our first quarter 2018 results. The entire Liberty team pulled together to overcome the first quarter's operational challenges and deliver record revenue and EBITDA.
The first quarter 2018 revenue grew 10% to $495 million from $449 million in the fourth quarter of 2017.
For the first quarter adjusted EBITDA increased 9% to $100 million from $92 million in the fourth quarter.
Annualized adjusted EBITDA per fleet increased to $20.4 million in the first quarter compared to $20.2 million in the fourth quarter.
Net income totaled $54 million in the first quarter compared to net income of $58 million in the fourth quarter.
First quarter results included a $3 million onetime nonrecurring expense related to the early retirement of debt in conjunction with our initial public offering. First quarter income tax expense totaled $8 million. Liberty was not subject to income tax prior to its initial public offering.
As we have said, we are a returns-focused company and at the end of the day, the sustaining cash flows from an investment will drive returns. Sustaining cash flow to the fleet is a metric we use to measure through cycle fleet profitability and is an important metric we use in the input in deciding future capital commitments.
We define sustaining cash flow per fleet as expected annualized EBITDA per fleet, less our expected annual maintenance CapEx per fleet. In the first quarter, our annualized adjusted EBITDA per fleet was $20.4 million. And as previously announced, our expected annual maintenance capital for this year is approximately $2.5 million per fleet.
General and administrative expense, excluding $3.3 million of fleet activation costs, totaled $19 million for the quarter. First quarter G&A did not include stock-based compensation expense as we did not finalize our equity compensation plan until after the first quarter. We expect G&A, including noncash, share-based compensation, to average $22 million to $24 million per quarter for the remainder of 2018. This is excluding fleet start-up expenses.
Interest expense and associated fees totaled $6 million for the first quarter, including the onetime nonrecurring expense of $3 million, relating to the early retirement of a portion of our term loan with proceeds from our IPO. Interest expense, excluding this nonrecurring expense, would have been $3 million, which is in line with what we anticipate on a quarterly basis for the remainder of 2018.
Income tax expense totaled $8 million for the quarter. For the remainder of 2018, we expect our reported income tax expense to be approximately 15% of pretax net income. For the fully diluted earnings per share calculation, our effective tax rate would be 24%.
We ended the quarter with a cash balance of $98 million and total debt of $107 million. At quarter end, we had no borrowings under the ABL credit facility; and total liquidity, including availability under the credit facility, was $311 million.
With that, I will turn the call back to Chris before we open up for Q&A.
Thanks, Michael. As we have always said, we are a returns and earnings-focused company and believe in aligning compensation with shareholder interest. Throughout the organization, we have significant variable cash compensation related to the main drivers of profit that our team members can control, such as throughput and gross margin.
For the executive team, our Board has decided that the majority of variable cash compensation will be driven by 2 metrics: return on capital employed and earnings per share. We believe that this provides structural alignment with shareholder interests and reinforces our commitment to make decisions based on long-term, through cycle value accretion, rather than short-term growth for growths sake.
We believe that 2018 will be a year defined by execution. We look forward to continuing to strengthening our customer partnerships and working together to increase operational efficiency and throughput, ultimately lowering the cost to produce a barrel of oil.
I want to thank our customers, suppliers and the whole team at Liberty who worked tirelessly to advance the shale revolution that is changing the world's energy landscape.
I will now hand the call back to our operator to start Q&A.
[Operator Instructions] Our first question will come from Sean Meakim from JP Morgan.
So a question, I guess, to start. Just your 2018 plan for capital allocation is unchanged, but as you look through the year and you need to make 2019 decisions, given lead times on equipment et cetera. I'm curious how those capital allocation priorities could change? I'm thinking, on our numbers you have pretty substantial sustaining cash flow yield in '19. And so if the market stays solid, is it realistic to think you'll be able to adequately reinvest all that cash? Or could those priorities begin to shift?
I think it's very unlikely that we will adequately invest all of our cash flow in 2019. We will nowhere near invest all of our cash flows in -- reinvest all of our cash flows in 2018. So next year, as we move further into the cycle, you're likely to see a greater percent of our cash flow in a return to shareholder mode and a decreasing percent in reinvested for growth.
Okay, great. And I guess, is there a sense of timing, as you plan to give the market a little more clarity or transparency. How you think that will play out over time?
I'd say that will be late -- likely late this year. Probably, towards the end of this year we'll have a clearer view for what growth CapEx plans are in 2019. We're in a constant dialogue with our customers.
Understood. And then I guess -- so speaking of that dialogue, so you highlighted the difference between customer decisions in the spot market versus those that are looking for dedicated fleets. Maybe, could you give us a little more context of how those conversations are going? Thinking about fleets 22 through 24, kind of how those discussions are evolving and what customers are really prioritizing for, those types of decisions?
It's always a combination of the history of the relationship, the depth of inventory, the commitment to efficiency and the partnership we have. We -- it's very firm where fleets 22 and 23 are going. We have multiple parties very interested in fleet 24. And that will be resolved where exactly it will go well in advance of its arrival.
Our next question is from Jud Bailey from Wells Fargo.
Wanted to just follow up on some of the guidance regarding EBITDA per fleet for the second quarter. Chris, if -- or Michael, if you could help walk us through kind of how to think about the increase that you're projecting, surpassing third quarter '17 levels? How much of that is maybe due to price reopeners? How much of it is just regaining some efficiency after starting up in the Eagle Ford? Maybe just kind of give us the moving pieces on how to think about the move up in profitability in the second quarter?
You bet. It's a little bit of both. Like-for-like, pricing was higher in Q4 than it was in Q3 of last year. It was higher again in Q1, the quarter we're reporting now, and it will be a little higher in Q2. But I think, the -- by far the largest driver of this sequential increase in the EBITDA per fleet run rate from Q1 to Q2 will be increases in efficiency and throughput. We had challenges at the start of this year. But again, I should clarify, most of the challenges were not in Liberty's controls. Our customer takes -- runs wireline, takes care of the wellheads, and supplies frac water. So if those things slow down, we slow down. But then there were some just unusual challenges at the beginning of this Q1. Now, I think we're back to normal weather conditions. Of course, there's always issues, but it's normal, those are normal. And our throughput performance across our fleets is strong and it's rising. That's what will drive our increased profitability, the dominant driver of it.
Okay. And then, my follow-up is a follow on to Sean's question. In the past, I think you guys have talked about your priority in terms of returning cash to shareholders, probably be more the avenue of like a special dividend. I wanted to just get an update on your thoughts. Is that still something you would prefer versus a more permanent dividend? Or any other type of return on cash?
Well, I think the third choices there is share buyback. And so which one of those is the right mechanism really depends on where we are in the cycle, obviously, what our stock price is and what looks to be the most effective way to return capital to shareholders. I think -- obviously, we'll get more concrete on that as we get closer to doing something like that. I think it's -- I think, as we said before, it's likely you will see a meaningful return of cash to shareholders in 2019.
Next question is from John Daniel from Simmons & Company.
Just 2 quick ones from me, really, Chris. When you look at the Tier 1 frac players, and you alluded to like the Tier 2 and Tier 3 guys, can you rank for us the factors which you believe separate the various tiers?
You know what [indiscernible] look, a most basic one upfront is ability to execute in the field, perform quality work; deliver a throughput that runs as fast as the operators can supply frac water and materials to the operator; perform safe operations; be reliable, as far as doing what you say and doing what -- delivering. Technology, having solutions that are differential from a commodity frac fleet. So I think there's a number of things that lead to a Tier 1 partnership. Do you have technology, not just for equipment, but for frac design, optimization? There's really a quite -- quite a range of quality of what gets delivered on location and the partnership of the customer.
Okay. Is it -- I mean, you guys have done a great job I think with the Sanjel assets. I'm just wondering if it ever makes sense, if you will, where you being Tier 1 could [ extend ] an acquisition of, call it Tier 3, libertize everything. Like how seamless are -- how would you see that playing out from a consolidation of lower -- it'd be rude to say lower quality competitors, but I think you know where I'm going.
Yes, well, look, number one, Sanjel's assets, the hardware that they had, were definitely not Tier 3, might argue, probably not even Tier 2. They had a good core equipment. There was meaningful upgrades to do to it. As you're well aware, we spent more upgrading it than we spent buying it. So with fleets -- I don't know, maybe half of the fleets out there, Ron can speak better than I, we probably could, with investment, libertize, but maybe less than half. There's certainly a good chunk of fleets out there, we wouldn't take them for free. We've got to deliver a high-quality piece of equipment that can deliver safe, high-efficiency throughput operations. But the even bigger factor is humans. And really, it's not the -- it's not just the people, it's the culture, the way people operate together, the way they communicate, the way they take ownership of what's going on. We have just -- we've not been an acquirer of businesses.
Okay, fair enough. One other one, sort of operational here. Just, have you seen any interest from clients to bring quiet fleets outside of Colorado? Just help us understand that opportunity set, and are they willing to pay for it?
Absolutely, absolutely. There are operations near towns and people let -- it's a higher percent in the DJ Basin, and it's also high in the Marsalis, Utica. In the other basins it's lower, but nowhere near 0. But there's an additional factor. When you have a fleet on location, where you can talk in a normal voice, you can communicate so much more effectively then you can in a typical frac fleet. This, first and foremost, is a significant health and safety. People know what's going on. You're much more aware of what's going on. The ability to communicate also helps efficiency. So yes, I'd say there's been significant interest from customers for Liberty Quiet Fleets in every basin we operate.
The next question is from George O'Leary from Tudor, Pickering & Holt.
Just curious, that second fleet coming at the end of -- that 22nd fleet -- sorry, coming at the end of the second quarter, so should we really not think about much of a revenue impact from that, this quarter or -- just trying to gauge exactly when that comes in, early June, late June? Just from a modeling perspective, that would be super helpful.
George, I'd model that mid-June. I think it's sort of -- so it's a relatively small effect. We'll have full utilization of it in Q3. The start-up costs will hit Q2 but the -- kind of the earnings power will kick in, in Q3.
That's very helpful. And then, last quarter you guys provided some helpful commentary on just the different nature of the fracs and longer pump times that you're seeing in the Permian Basin in particular, versus some of your legacy areas. I wonder, if you couldn't help kind of compare and contrast where you're seeing the biggest rate of change in profitability, as we head into the second quarter? Is it really getting those Permian frac fleets, the Texas frac fleets, generally kind of up to snuff with the rest of the equipment? And then maybe, compare and contrast the pricing dynamics in the Permian Basin versus some of the other areas?
You bet. If you want to say rate of change in profitability, the last quarter, and probably currently, it's Eagle Ford. We're brand new in that basin. And again, you know our style, we're not shopping around for the highest spot price, we're trying to find a partner we can work together for the long term and drive efficiency and throughput. So we're prospecting for different people. So the original arrival in a new basin, not necessarily a new fleet but in a new fleet in a new basin, there's reduced profitability. And that -- and so we called out the Eagle Ford as an area that's going to have a significant change in profitability today than it had 3 months ago or 6 months ago. So that's, I would say, the greatest rate of change. As we mentioned before, the Permian market, like-for-like, has higher pricing but a little bit lower efficiencies and throughput and all that, because it has experienced rapid growth, the marginal wireline crew coming on, or water supply operators, it's just on the margin, it's lower than the other basins. So you suffer some inefficiency and throughput from third parties there, pricing off -- has fully offset that. But it's still at the tip of a more rapid growth. So if I had to say, the second -- basin with the second fastest growth in profitability, that would likely be the Permian. Michael will kick me if he thinks I'm saying it incorrectly. But I'd say, the economics in the Permian are good already. So -- but yes, certainly. And I would say, if you look out Q2, Q3, we'll probably see increased profitability in every basin we operate. And that is continuing to innovate and finding new ways to get more done in a day.
And George, just to say, I think our efficiency differential in the Permian versus the average frac fleet, is the same as it is across the other basins. So whereas, we might be -- our Permian fleet may, because of outside forces, get slightly less done in a day than some of the other fleets. As you say, pricing obviously is there but the differential between the average frac fleet and the Liberty frac fleet is the same. So we think that the whole basin itself is going to come up in a little bit of efficiency, and we'll continue to maintain that differential.
[Operator Instructions] Our next question is from Scott Gruber from Citigroup.
So I do applaud the variable comp formula, it's great to hear. Another concern of investors in the marketplace today is they're trying to frac companies to go out and order capacity on a speculative basis. You guys are return-focused, you're achieving increasing scale as you grow here, you're up over 20 fleets. Is it time to shift to a mode where you deploy growth capital? But only after demanding a contract or receiving a contract from customers with some [ fees ]?
Well, first of I'll say, Scott, we've never ordered a fleet on spec and then hope we'd find a home for it. All of -- from the start of our company, all of our ordering of new fleets is based on discussions with customers, dialogues. We know where that fleet is going and it's going to be there for a long time. Even through the last downturn, we kept all of our fleets busy. So we're not buying fleets, parking them and hoping we can find someone to employ them. But the contract nature of the relationship with frac has historically been different than it has been with drilling rigs. And I think that changes a little bit with the cycle but it probably doesn't radically shift different than a rig. It's a little more human-focused than equipment spec-focused business. So somebody can sign a long-term contract with a company that's performing okay today, and they have high turnover, their quality declines and I don't think a customer wants to be faced with a multiyear, take-or-pay commitment. There are some, but for us, I fully agree with your point, we are very careful and disciplined about ordering a fleet. We only order a fleet if we know where it's going to work for the next 1 year or 2 years or more.
Got it. And obviously, your track record attests to your comments. But I'm just curious, you're in the Tier 1 of frac operators, you're able to execute at the well site, are you not able to go and get that contract? I mean, it just seems like customers in this market where there's very uneven performance, would want to lock in your crews -- would want to give you that commitment and get that commitment from you that that crew is going to continue to work with their crew. It just strikes me that the dynamic is such that, given the job complexity and uneven performance, that contracts should be a viable option in this market.
They are doable. We have contracts like that for fleets. So it is doable but is it the best model? Is it the best balance of the tradeoffs? We've mostly decided, no. We want to be a partner. If we're working for a customer and they've got 4 fleets and we're 2 of their 4 fleets. We want to be -- and we like being in that situation and we are in that situation with some where our fleets are outperforming the other fleets, those guys could cut their work in half, and our fleets will keep working. But if oil prices drop $20, our customers' revenues are going to decline -- our revenues, and we will do that proactively in dialogue, our revenues will decline, our input costs will decline, all the materials we buy will be softened, we have a very large percent variable comp, our variable comp will flex down. So our model is really a long-term partnership with our customers. And in this cyclical business, it's -- they don't know what they're going to do over the next 2 or 3 years in a rigid format. I know they're going to be active in drilling some amount of wells, that amount of wells may vary, the revenue and returns they get are going to vary, and we work through that cycle with them as a partnership.
Got you. Do you think you could ever trade a contract where you lock in a certain percentage of the customer's workload as a way to, kind of, flex with them if needed?
We could, we could. We have a range of arrangements like that. But it isn't -- we don't want a fixed percent. What we want is if we have a dedicated fleet, we want that fleet fully loaded, fully loaded. So if they're running 2 frac fleets and we're 1 of 2 frac fleets and their work goes down 50%, we don't want a 75% of a frac fleet for them, we want to work -- we want to keep that fleet fully loaded for them. That's what happened for us in the downturn last time, that's what we want to have happen in the downturn next time.
I do appreciate the color, and again, certainly applaud the comp formula.
Thank you. And we appreciate your focus on discipline in the industry. It's absolutely important.
And our next question is from Vebs Vaishnav from Cowen.
Just for clarification. It seems like you are guiding to around $22 million fleet profitability in 2Q and just over 21 fleets. How much of fleet reactivation cost is included in that guide? And also, when you report, would you be adding the stock comp just to make it all apples-to-apples comparison?
Yes, Vebs, I think reactivation -- sort of fleet activation is sort of around $1.25 million to $1.5 million on a fleet, so we'll have just north -- probably, north of $2 million in the Q2 numbers. We will include stock-based compensation in our G&A, that's an ongoing cost as far as we're concerned. So in those numbers that we're guiding to, we're using that as an expense. And you're right, I think, we will have just a hair over 21 fleets active for the second quarter.
And we didn't guide to any particular EBITDA per fleet metric, we just guided to over a certain threshold.
Got it, okay, okay. Just more generally, if we think activity slows down in Permian and moves to other region, can you help us walk through like the steps, time and costs involved in making any relocation decisions if they need to be made? What I'm getting is like, how much is the wait time, do you guys wait for 1 month, 3 months, before you decide to reallocate the fleet? Who bears the cost? How much does it cost? And the employer allocations. That would be very helpful.
Yes, you bet. First, I would say pretty unlikely that, with what's going on now, and what may continue to soften, that Liberty would move a fleet. The total amount of work in the Permian, if it indeed rolled over and shrunk 10% or 20%, very unlikely that would lead to Liberty redeploying a fleet out of the basin. There might be redeployments out of the basin, though it's very unlikely to be Liberty. Yes, and if -- and we can move basins between -- fleets between basins, we do, do it sometime and mostly it's to catch piles of work here or if we've got a slow down or a gap here we'll move a fleet. But -- whatever, a softening in the Permian leading to a fleet redeployment, pretty unlikely in the case of Liberty.
Even during the downturn, we did not actually move any of our fleets permanently. We redeployed a Rockies' fleet into the Permian, out of the Powder River when that rig count went down to 0. Generally we -- the only additional cost, there's a little bit of additional accommodation costs for the crews. They still get paid the same, they're on very much the same schedule. So we -- when the Powder went down to 0, we within, I think, 1.5 weeks, we had redeployed that fleet into the Permian, in fact they walked off the last -- the last site in the Powder, they drove south, they drove straight onto location, they started fracking, we hadn't -- didn't even have hotels set up for them at the time. So again, it's -- the fleets are on wheels, if you had to redeploy to a basin where we didn't have a presence, which is what we did in the Permian, generally that's a little more difficult. But, yes, we proved during the depths of the downturn at the beginning of 2016 that it's possible and with the contacts and the demand for Liberty services and Liberty-style first-tier fleets, we can do it.
That's pretty impressive. And last question, if I may. If I think about Tier 4 costs versus Tier 2 costs, obviously, Tier 4 I think it's a little expensive, I don't know, maybe 20%, 25%. Could you compare contrast on the returns that you make on Tier 4? Do you get higher margins on Tier 4 to compensate for the higher cost? You or industry in general?
In general, no. I mean, you'll have a Tier 4 fleet on the site or one of our fleets that we built last year. Pricing is the same for both of those 2 fleets. So yes, there's a little bit of additional cost on a Tier 4 now when you're building, but as we move through the cycle, obviously, as a returns-focused industry, and especially as a returns-focused company, that plays into our capital allocation decision. But again, it's a relatively small amount, when you're thinking this is a 10-year fleet, right? I mean, and as we put -- there is a huge amount of expense that goes into running this fleet for 10-plus years. So that increase of that initial capital doesn't really change the return profile that much.
And you mentioned 20% to 25% increase that the -- the all-in fleet cost is less than a 10% increase in the fleet.
Correct.
And, ladies and gentlemen, this will conclude our question-and-answer session. I would like to turn the conference back over to Chris Wright for any closing remarks.
Thanks, everyone, for joining us for the call today. We appreciate your interest in Liberty and certainly love the questions and dialogue and feedback. And are proud to see American energy growing and marching forward and most importantly, the technology advancing. So we and the industry keep getting better at what they do. Thank you so much.
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect your lines.