Liberty Energy Inc (LBRT) 2018 Q2 法說會逐字稿

Good morning, and welcome to the Liberty Oilfield Services Second 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, 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 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.

Good morning, everyone, and thank you for joining us.

I'm quite proud to discuss with you today our second quarter 2018 results. Working together with our customers, the Liberty team drove average throughput to new all-time highs, delivering record revenue, net income and adjusted EBITDA for the quarter. These results are made possible by our relentless focus on efficiency, which is bred into our DNA and leads to lower well costs for our customers. High-efficiency operations are a win for Liberty and a win for our customers, a true partnership.

Exceptional utilization in the second quarter from a combination of cooperating weather and smooth customer scheduling, combined with our efficient field execution, led to our record results. Such alignment can't be counted on every quarter, but the preparedness of our high-efficiency crews and superior equipment enables us to take advantage of scheduling synchronicities.

In the second quarter our revenue was $628 million and net income was $95 million, or $0.71 per fully diluted share. Adjusted EBITDA for the quarter was $149 million, or $28 million per average active frac fleet on an annualized basis.

Working together with our customers, the Liberty team continued to achieve improvements in operational efficiency across the entire fleet, while maintaining exceedingly safe operations. This performance is the backbone of strong demand for our high-efficiency fleets that deliver differential frac services. Our diversified basin footprint and premium service quality leads us to believe that we will continue to generate strong returns on capital employed over the next few quarters regardless of market developments.

Liberty was built for long-term success through up and down market cycles, as illustrated by our trailing-12-months, pretax return on capital employed of 43%. 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 when appropriate.

I'm pleased to announce that yesterday the company declared a quarterly cash dividend on its common stock of $0.05 per share, to be paid on September 20, 2018, to holders of record as of September 6, 2018. We will maintain a flexible approach to returning capital to shareholders, which may also include stock repurchases and special dividends in the future.

Global oil markets, as reflected in the OECD inventory data, continued to normalize at a rapid pace. Roughly 75% of the record OECD excess oil inventories from early 2017 have already been drawn. This rapid inventory drawdown has occurred in spite of the very rapid growth in U.S. oil production, the best of both worlds for the U.S. oil and gas industry.

Liberty's operations in the Permian continue to grow and thrive. Local sand volumes in the pipeline for several quarters, now began to materialize in meaningful quantities during the second quarter and we see this trend continuing in the third quarter, driving down well costs for our customers. With significant new industry pumping capacity added to the Permian Basin during 2017 and 2018, while takeaway limitations have created temporary production challenges, we are pleased that the developing imbalances for frac services in the Permian has not yet impacted Liberty fleets.

As always, we will work in partnership with our customers to navigate the ever-changing oil and gas landscape. We have not seen any significant reduction in our customers' projected activity in the Permian due to takeaway constraints and widening differentials. However, we expect it will affect the completions market. Basins outside the Permian remain very constructive, but there may be some effect of the Permian softness spilling over to other basins. We could also see some scheduling adjustments in the fourth quarter, as operators adjust completions to meet preannounced capital budgets.

For the second quarter, we averaged 21.3 active frac fleets. We deployed our 22nd fleet late in the second quarter under a dedicated arrangement with an existing customer. We have experienced some delays in receipt of critical components for our new fleets under construction, and therefore we anticipate deployments of our 23rd and 24th fleets in the fourth quarter and very early in the first quarter of 2019, respectively.

As an example of one of our recent efficiency-focused technical efforts, over the past 24 months Liberty has focused on developing a next-generation blender design, with the goal of improving uptime on this key piece of equipment. Approximately 50% of Liberty blenders have now been upgraded to our latest technology and the rest of the upgrades should be completed by early 2019. They deliver up to an order of magnitude improvement in proppant pumped between failures. We are excited by this step change in operational reliability and will continue to develop and implement other innovations like this to provide our team in the field with the best possible equipment.

I will now hand the call over to Michael Stock, our CFO, to discuss our financial results.

Good morning.

We are very pleased with our second quarter 2018 results. The entire Liberty family pulled together to provide exceptional execution for our clients and deliver record revenue, net income and adjusted EBITDA.

For the second quarter 2018 revenue grew 27% to $628 million from $495 million in the first quarter. Net income totaled $95 million in the second quarter compared to net income of $54 million in the first quarter.

Second quarter adjusted EBITDA increased 48% to $149 million from $100 million in the first quarter. Annualized adjusted EBITDA per fleet increased to $28 million in the second quarter compared to $20.4 million in the first quarter.

Given the roughly flat pricing environment experienced year-to-date, we expect annualized adjusted EBITDA per average active fleet of between $22 million and $27 million for a typical quarter. Unusual weather and logistics challenges drove the first quarter below this expected range. The second quarter had no unusual exogenous challenges and we delivered simply stellar operational efficiency, with unusually low number of nonpumping days for the dedicated fleets. The result was $28 million annualized adjusted EBITDA per average active fleet, which is above our expected average range.

Though we will always aim for exceptional performance, as we move further into the third quarter reality tends to present schedule and throughput challenges that are to be expected, but not always avoidable. 1/3 of the way into the quarter we are experiencing more than normal dedicated fleet scheduling challenges, likely pushing our results for the third quarter to the lower end of our expected $22 million to $27 million range.

As we have said, we are a returns-focused company and at the end of the day the sustaining cash flows from an investment are what drive returns. Sustaining cash flow per fleet is a metric we use to measure through-cycle fleet profitability and is an important metric we use as an input into 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.

Through the second quarter our year-to-date annualized adjusted EBITDA per fleet was $24.6 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 $24 million for the quarter, or 3.8% of revenue. Second quarter G&A includes stock-based compensation expense of $1.1 million. We expect G&A, including approximately $1.6 million of noncash share-based compensation, to average between $24 million and $27 million per quarter for the remainder of 2018, excluding fleet start-up expenses.

Interest expense and associated fees totaled $3.5 million for the quarter.

Second quarter income tax expense totaled $16 million compared to $8 million for the first quarter. Liberty was not subject to income tax prior to its initial public offering. For the remainder of 2018 we expect our reported income tax expense to be approximately 15% of pretax net income. For fully diluted earnings per share calculations, our effective tax rate would be 24%.

We ended the quarter with a cash balance of $83 million and total debt, net of discounts and issuance costs, of $107 million. At quarter-end we had no borrowings under our ABL credit facility and total liquidity, including availability under the credit facility, was $318 million.

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

Delivering this level of performance not only requires everyone on Team Liberty rowing hard and in concert, it also requires an amazing amount of cooperation with our customers and our suppliers. It is only that whole team together that can do this. And my hat's off to all of them.

And we look forward to answering your questions today. Thank you for being on the call.

(Operator Instructions) And today's first question comes from John Watson of Simmons & Company.

I think the quarter evidences what you all have discussed regarding throughput, and I want to ask a question there. Can you talk to us about the gap between your most and least efficient fleets today and how you continue to close that gap?

Sure. Obviously the longer we've been working with a customer, the more we've worked together to optimize wireline operations and water delivery and wellhead and pressure testing -- so it's mostly a fact of how long has that relationship been engaged. So obviously we've added a lot of new customers over the last 12 or 18 months, some of those relatively recently. So those ramp up with time as we work together. After every pad we sit down and go over every minute that was expended on that pad and how can we trim those downtimes and move it up. But there's basin issues and logistic issues. But it is a process, it is a process.

Sure. Sure, makes sense. And the release talks about the dividends not constraining future growth. Is there any update on growth plans into 2019? I know you mentioned on the last call that it was too early then. Do we have more clarity today?

Well, we're in lots of discussions with customers for 2019. And we'll probably evaluate 8 to 12 opportunities for next year. I think the actual ones we will take action on will be much lower than that, obviously. But, no, we haven't thoroughly committed to any one yet for growth on 2019 growth plans. We'll probably have a little more color on that in the next call, but it's certainly a continuous dialog and certainly we have significant growth from existing customers planned next year really across the basins, so -- but no specific plans, I mean nothing to announce right now.

And our next question today comes from Sean Meakim of JP Morgan.

So could you maybe help us with how much of the incremental margin per fleet came from efficiency gains, specifically in the Permian because that's been a key initiative for you? And thinking about the look forward, to what extent are your scheduling changes driving -- being driven by concerns about budget exhaustion, completion programs running ahead versus Permian takeaway concerns, which you've noted has not really been a direct factor yet for your specific customers?

Yes. So as we referred to in the release talking about Q3, I would say probably none of that is due to budget exhaustion. And really none of that is due to Permian takeaway issues. So this is just simply when you work on efficiency and you get high throughput done, a typical problem for Liberty is a customer thinks a pad's going to take 4 weeks and we get it done in 3 weeks. Well, that's fabulous, but if you've got to wait a week to start the next pad, you lose the benefit of that.

So in Q2 I think we had great communication going and we had -- our customers in general are having pads ready early, so we flowed one onto the next. And this quarter we just had a number of issues where people weren't quite ready with the next pad. So it's a dedicated fleet with customers. But we've had several of those where just unrelated to frac issues, have slowed down preparation on our customer's end. And so we end out with more days not fracking. That's -- but not related to Permian, not related to takeaway and not related to budget exhaustion.

Got it.

Sean, and just to answer the first part of your question, I mean, we were in a roughly flat pricing environment Q1 to Q2. So really the improvement in Q2 was really driven by overall efficiency, which was a combination of throughput and the incredibly synchronous scheduling that we got with customers.

And was that more outsized toward the Permian, given that's where there's been more room to catch up? Or would it not be fair to characterize it that way?

Yes, honestly it crossed the basins, across the basins. I don't think any one basin was the dominant driver of that.

And then as you look ahead to the fourth quarter, any sense that those other factors may become a bigger piece? I mean, I guess it's a bit unclear to say whether or not you could have some of these specific scheduling issues that far out.

Yes, we don't know about that. As we said, I think we're having a little bit above-normal issues on schedule this quarter. So all things being equal, those issues are probably a little bit better in Q4. But the budget exhaustion thing is a question we still don't know. But that's -- and as long as we know in advance we usually can work around it. The struggles with those, and we had some of it last year, was just sort of short -- not much advance notice for changes in plans of our customers. Those are those holes you can't really fill.

Got it. That's very helpful. And just on the new-build push-out maybe could you give us a little more detail on the components that are delayed and any risk to customer acceptance for those, where they were specific -- where they were targeted, or impact to any customer E&P well programs? Just thinking about sort of the secondary order effects of that move.

No, it's still a ways out in advance. And we're in a constant dialog with our customers. We've got a large enough fleet now we have some flexibility. So, no, I think it will not lead to interruptions or problems for our customers. Obviously that's top of the heap for us. So, no, we're not worried about that. That is going to work just fine.

Ron can, if he wants, elaborate a little bit more on the components. But there's one critical component that we're very particular on which one we want to use. And of course that happens to be what we have in backlog right now. But this has been an ongoing dialog for months.

Yes, just specifically to exactly where that delay lined up, we had our supplier for transmissions run into a specific supply chain challenge with a component that they could not source easily elsewhere. And so that's led to a delay in manufacturing from their standpoint. It was a component manufactured overseas and there were some challenges there and so they've had to rework that.

Like Chris said, it's not going to impact our customers at all. We anticipate maybe a month's delay in total. So we're working through that as best as we can with them, but hope to have that resolved and not see it be an issue in the future.

And our next question today comes from Jud Bailey of Wells Fargo.

Question just on thinking about the fourth quarter. You guys outlined guidance of EBITDA per fleet between $22 million and $27 million for each quarter of 2018. And I just wanted to confirm for the fourth quarter -- in your inherent guidance are you contemplating some budget exhaustion? Are you contemplating that kind of dynamic in your scheduling, or would that be inherent in hitting the low end of that guidance range for the fourth quarter? Just want to make sure we're thinking about it the right way.

Yes. That wide range isn't even meant so much as guidance. It's like with this pricing arrangement and sort of the normal challenges you always have in oilfield operations and scheduling, that's what we'd expect.

We should be in that range at today's pricing. In Q3 I think the pricing is not going to -- will be basically the same as it's been. But we've had some scheduling changes. So we're more trying to explain why was Q2 so much higher than Q1 and Q3's going to be a little lower than Q2. It's not changing market environment. It's not changing demand for our fleets. It's just simply the speed of throughput and operations. So Q4 is just still a little further out.

So, no, it is not a fence post for Q4. We don't know what's going to happen in Q4 in both the pricing and budget exhaustion scheduling front. I don't think we'll see dramatic things there, but we may see something. And, as you said, Jud, it's too early to really know how schedule and budget stuff will unfold in Q4.

Okay, thanks for that. And then just speaking of pricing, can you remind us? You guys have a number -- obviously all your fleets are on kind of dedicated arrangements. How do we think about pricing reopeners and kind of the timing of that? Is that typically a year-end type of negotiation? Is it every quarter? How do we think about when you may be susceptible to any type of pricing softness in the dedicated market? Is that a 1Q '19? Or help us think about that, please.

Some of the arrangements are pricing fixed for the year. We have a number of those, but they'd still be a minority of the fleets. Most often they're just pricing agreements and we march forward in dialogue with our customers. If oil prices drop $30, we're going to talk quickly. And if oil prices bump up $30, we'll talk pretty quickly, too. So they're really more reflective of significant moves in market conditions. But it is a constant dialogue. Some of them have fixed term, but I would say that's 1/4 or 1/3 of the fleets.

Okay. Great. Thanks. And then, if I could squeeze in one more, the newbuilds for the next couple of fleets, some of your competitors are scrapping plans to reactivate, or pushing things out. And you guys seem to have a pretty high level of confidence that the next 2 fleets will start in the fourth quarter and the first quarter. Could you give us some insight (inaudible) if you're close to securing contracts? How do you think about that?

Wait; I didn't hear the last bit. Again, Jud, say that again.

No, I just said kind of level of confidence on getting the next couple of new-build spreads deployed, do you have contracts lined up?

We do. We do. Yes, we're quite confident in that. The next fleet, what we call Fleet 23, will go out in Q4, probably the first half of Q4. But, yes, we have customer and work and agreements lined up for that.

And for the last fleet that was going to go into the Permian, we're in dialogs. I think, given the market softness and all that, we will probably, almost certainly now, I'd say place that fleet in the Rockies. Lots of demand for that. We're kind of sorting out who gets that fleet. And then that will tie together with what plans we have, we may have, for fleet expansion in 2019 as well. But, no, we're not worried about deploying both of those fleets into dedicated arrangements at good profitability for us and great throughput and economics for our customers.

And our next question today comes from Connor Lynagh of Morgan Stanley.

Just wondering if we could build on that conversation a little bit. So obviously you've got a very large Rockies operation. One of the debates, it seems to me, is whether or not other basins will accelerate if the Permian softens somewhat. So can you talk about the demand indications in the Rockies and Eagle Ford, and just sort of what you're expecting as we move into 2019 here?

Yes, you bet. There are some customers that have assets in both basins and that can move capital. I think we heard Conoco announce such a thing. So there will be some of that. But the majority of the Permian operators, they're Permian operators and they don't have operations of scale in other basins. So I think you'll see a little bit of capital migrate out of the Permian to other basins. But I think more -- the activity level in the Bakken, for example, is just -- at today's prices and with the DAPL pipeline in there, the differential between crude price realization in the Bakken and WTI, is pretty low. That differential's small. So the drilling economics are superb in the Bakken. So I think the activity -- increase of activity next year in the Bakken, it's not so Permian-related. It's just, hey, we've got great drilling economics, we've got takeaway capacity. Let's develop our resource.

Got it. And could you maybe talk to the supply side in those other regions? I mean, it seems that from most accounts there's been a lot of incremental supply coming out in the Permian. Have you seen that in those other regions?

You know, not as much. There certainly has been new capacity added to the regions we're in, because if you look back 12 or 18 months, activity level in every basin has gone up. But certainly it's gone up the most in the Permian, right, which made it a huge magnet for deploying new capacity.

We also had this factor that, think of you're a Tier 3 frac player and you're in one of the other basins and you really can't get frac work, right? You only can get it at a price so cheap that you can't do it for long. So what did those fleets do over the last 12 or 18 months? The majority of them moved to the Permian. Market in the Permian was just so tight and the extrapolation of where it was going in activity level -- just up, up, up. So if you were struggling in other basins, your odds of success were much better in the Permian.

So we had a lot of fleet migration from other basins to the Permian. We had a lot of building and activity. So I'd say the majority of the incremental -- the vast majority of the incremental frac capacity has gone to the Permian. But there's been fleet. We've added fleets in all of our basins. So I think it's not that there's been no additions elsewhere, but additions more lined up with the pace of increasing work. And I think that was true in the Permian.

But now we've had -- we're having sort of a -- plateau is even probably too negative of a word, but we're having a slowing in the growth rate of frac activity in the Permian. When you couple that together to a faster rate of fleet addition that may increase the frac activity, you get the market softness we're seeing and may see for 1, 2, 3 quarters in the Permian.

And our next question today comes from George O'Leary of Tudor, Pickering and Holt.

On the efficiency part, obviously an awesome quarter for you guys. I wonder if you could just dig in a little bit more there and maybe talk about the -- even if you won't give out the exact nominal number, the progression of stages per day and days per month worked on a quarter-on-quarter basis, Q1 to Q2, just to kind of help frame just how much more efficient you were quarter-over-quarter.

Well, I think you can see it. Look, pricing was basically flat in Q2 versus Q1. Right? So you see the rise in revenue per fleet. Off the top of my head I think it was 18%, right? We went from $100 million a fleet to $118 million a fleet at basically the same pricing. So probably 18% more frac stages per fleet, I'm saying in round numbers, you saw increase.

Now a lot of the problems in Q1 were that's cold-weather water supply. If our customers can't deliver water we can't frac. So we didn't have any of those problems. We had sort of a flat level -- no, we don't share the details or the number because they also change. What's our base expectation? That moves with time. But we have sort of a base expectation of what we think is reasonable for a number of hours a day of pumping and number of frac days per month. And of course that depends on basin and customer and type of work.

But in Q1 all those exogenous factors drove that down below really the low end of what we think is a normal range. But we get why it happened. And then in Q2 we just had great lineups. But I think in 2012, our first year in business, we exceeded $118 million in revenue per frac fleet. We only had a single frac fleet, but pricing was dramatically higher. Like, the actual amount of frac work we did in Q2 of this year per fleet was probably, of order, twice what we did in 2012. But for us, we don't control pricing in the frac world; that's supply-and-demand dynamics. But the thing that really aligns us with our customers is that we can get more done faster. It helps our profitability. It lowers their well cost and gives them greater certainty in bringing production online.

But certainly the highest throughput and efficiency we've had of any quarter was the quarter we just finished. We hope it doesn't stay as the record holder for very long, but it will for at least another quarter just given this -- the not wildly out of the ordinary, but a little bit exacerbated scheduling challenges, which just means gaps between finishing one pad and moving to another pad, that we're experiencing in Q3.

Okay. That was super helpful color and it was a damn good quarter. You've actually answered my second question in that answer, so I'll pass the mic to somebody else.

Thanks for that, George. The whole team appreciates the comment.

(Operator Instructions) Today's next question comes from Jon Hunter with Cowen.

So first one is you mentioned upgrading the blender designs to the newest technology on about 1/2 your fleets and then the rest of them will be done in 2019. How much capital are you putting towards those upgrades?

Jon, this is Ron. Yes, it's a relatively modest amount of capital. We've always been focused on collecting a significant amount of data around failure points. And so we've done a lot of work on the blender specifically and understanding exactly where we need to do some work. And so that led us to identify a few key areas we could focus on. And so what that's ultimately meant is that we've made significant steps forward without a significant investment of capital on each of those blenders.

The investment's really in the design, engineering, the gathering of data, the testing. But we're always happy to invest those dollars. And then you find out -- what's the root of the problem, how do we solve the problem root? And now we get the benefits of that for the next decade. But, yes, to Ron's point, the actual capital spent to upgrade that blender, in dollars out of my wallet it's significant -- if you had to fix your car. But for our business and capital deployment in the business, not meaningful.

Great. Thanks. And then an unrelated follow-up: we've been hearing a bit more about electric frac fleets, and just wondering what your thoughts are in terms of viability, comparing them to the fleets that you have in terms of payback and returns. Just if you could speak broadly to that, that would be great.

You bet. Look, Ron and I and most of our team are career tech nerds. I'm an electrical engineer by training. So we've looked at electric frac fleets really since we started the company. And we've watched that technology and it's intriguing. To date, for us the trade-offs haven't arrived yet.

The downside is that they cost a lot more, between 50% and 100% more to put together a fully electric frac fleet. They have some benefits. One is the significant noise reduction. But the noise level of our quiet fleets is pretty much right in line with an electric frac fleet. So we've found another route to that advantage.

The other one, and I think that customers like a lot, is that you run on natural gas in the gas turbine instead of diesel. It's cheaper and in the field sometimes you've got it available. So we've addressed that one with these dual-fuel fleets. We have a number of dual-fuel fleets today. And for a Tier 2 engine when you run it in dual-fuel mode you can get up to 70% of the fuel you consume is natural gas and you supplement it with 30% diesel. The new Tier 4 engines, with dual-fuel versions of them, burn 89% natural gas and 11% diesel. So if we can get 90% of the fuel -- 89% of the fuel switching savings, the same noise profile and at dramatically lower costs, for us and our customers today, that's been a better tradeoff.

The other issue is gas supplies. It's not just like the gas flowing out of the nearby well on the pad. Right? You need several million Mcf a day, several, to run a frac fleet on that. So with a dual-fuel fleet, if you have problems with gas supply, just increase the diesel content. You've still got this robustness. With an electric frac fleet, if you lose your natural gas supply, you're not fracking. And in the vast majority of well pads, there is no pipeline-supplied reliable, several-million-a-day natural gas.

Now, if you've got large infrastructure, you're in the middle, you've got a gathering system and reliable supplies of natural gas, absolutely you can do it. But it's still a significant minority of the available wells to frac, and the fuel consumption and economic benefits aren't there yet. But technologies evolve and we're watching them. And as they evolve and better, might Liberty have electric frac fleets down the road? Very possible, very possible. We're constantly watching that. We love new technology, as you probably can guess.

So, ladies and gentlemen, this concludes our question-and-answer session. I'd like to turn it back over to Chris Wright for any final remarks.

Thanks so much for everyone's time today. In addition to thanking our customers, suppliers and the whole team at Liberty, I also want to thank everyone else who works in the oil and gas industry. We enabled every other industry to perform at modern levels.

We are holding an Energy Proud rally today in Denver to celebrate the impact of oil and gas on human lives. Our Top 10 list of oil and gas benefits is headed by #1, doubling human life expectancy since the first oil well was drilled. Human life expectancy globally was 35 years before the first oil well was drilled. It's over 70 years today.

We've also seen a dramatic drop in global extreme poverty, meaning living on less than $2 a day in today's dollars. When the first oil and gas well was drilled, 90% of the global population lived in extreme poverty. Today that number is below 10% and declining rapidly.

We thank all of you on this call for being part of the world's most important industry. Thank you for your time today.

And thank you, sir. Today's conference has now concluded and we thank you all for attending today's presentation. You may now disconnect your lines, and have a wonderful day.