Liberty Energy Inc. (LBRT) Q2 2018 Earnings Report, Transcript and Summary

Good morning and welcome to the Liberty Oilfield Services Second Quarter 2018 Earnings Conference Call. All participants will be in listen-only mode. [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 the 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 the 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’s CEO, Chris Wright. Please go ahead.

Good morning, everyone, and thank you for joining us. I am 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 or 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 crudes 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 pre-tax 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 am 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 continue 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 continued 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 that 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 have 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 can also see some scheduling adjustments in the fourth quarter as operators adjust completions to meet pre-announced 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 is 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 will deliver up to an order of magnitude improvement in proppant pumped between failures. We are excited by this step change in operational reliability and we 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 of 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 of 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 fourth – 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 we experienced year-to-date, we expect annualized adjusted EBITDA per average active fleet of between $22 million and $27 million for the second quarter. Usual 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 non-pumping 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 as we expected, but not always avoidable. One-third 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 rate of our expected $22 million to $27 million range. As we have seen, we are returns focused company and at the end of the day, the sustaining cash flows from an investment of what drive returns. Sustaining cash flow for the fleet is a metric we use to major through cycle fleet’s profitability and is an important metric we use as an input into deciding future capital commitments. We define sustaining cash flow to the fleet as expected annualized EBITDA per fleet lets our expected annual maintenance CapEx per fleet. Through the second quarter, our year-to-date annualized adjusted EBITDA for the 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 non-cash share-based compensation to average between $24 million and $27 million per quarter for the remainder of 2018 excluding fleet startup 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 pre-tax 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 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 the 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 hats off to all of them and we look forward to answering your questions today. Thank you for being on the call.

Thank you. We will now begin the question-and-answer session. [Operator Instructions] And today’s first question comes from John Watson [ph] of Simmons & Company. Please go ahead.

Hey, guys. I think the quarter evidences what you will discuss regarding throughput and I want to ask a question there. Can you talk to us about the gap between your most and least efficient cleats today and how you continue to close that gap?

Yes, sure. Obviously, the longer we have been working with a customer, the more we have worked together that optimized 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 have had a lot of new customers over the last 12 or 18 months some of those relatively recently. So, if those ramp up with time as we work together after every pad we sit down and go over every minute that was expanded on that pad and how can we trim those downtimes and move it up. But there is basing issues and logistic issues, but it is a process, it is a process.

Sure. It makes sense. And the release talks about the dividend 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 are in lot of discussions with customers for 2019 now and we will 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 we have been firmly committed to anyone yet for growth on 2019 growth plans, we will probably have a little more color on that on the next call, but it’s certainly a continuous dialogue and certainly we had significant growth from existing customers planned next year really across the basins, but no specific plans, I mean, nothing to announce right now.

Understood. Well, congrats on the great quarter guys. I will turn it back.

Thank you.

And our next question today comes from Sean Meakim of JPMorgan. Please go ahead.

Thank you. Hey, good morning.

Good morning, Sean.

So, could you maybe help us with how much of the incremental margin per fleet came from efficiency gains, specifically in the Permian as that’s been a key initiative for you and thinking about the look forward, to what extent are these scheduling changes driving or being driven by concerns of budget exhaustion completion programs running ahead versus Permian takeaway concerns, which now have 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 have got high throughput done, a typical problem for Liberty is, customer thinks the pad is going to take 4 weeks and we get it done in 3 weeks. Well, that’s fabulous, but if you 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 having pads ready early so we flowed one on to the next and this quarter we have just had a number of issues where people weren’t quite ready with the next pad. So, it’s a dedicated fleet with customers, where we had several of those, we are just unrelated to frac issues, have slowed down preparation on our customers 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.

And just to answer the first part of your question there, I mean, we are 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 towards the Permian given that sort of has been more room to catch up or we are not going to characterize it that way?

Yes, honestly across the basins. I don’t think anyone 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 and then I guess it’s a bit unclear to say whether or not you could ask some of these specific scheduling issues that far out?

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

Got it. That’s very helpful. 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 in fact to any customer E&P well programs, just thinking about some of the secondary order effects of that move?

No, it’s still the ways out in advance and we had a constant dialogue with our customers. We get a large enough fleet now. We have some flexibility. So, no, I think that – 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 are not worried about that. That is going to work just fine. Ron, if you want to elaborate a little bit more in the components, but there is one critical component and we are very particular on which one we want to use and of course that happens still we have a backlog, but thinking that this has been ongoing dialogue for months.

Yes. Look 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 have to rework that. Like Chris said, it’s not going to impact our customers at all. We anticipate maybe a month delay in total, so we are working through that as best as we can with them, but hope to have that results and not to see of being an issue in the future.

Got it, okay. Thank you very much for all that detail.

You bet. Thanks Sean.

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

Thanks. Good morning.

Good morning, Jud.

Hey, a question just on thinking about the fourth quarter, you guys outlined guidance EBITDA per fleet between 22 and 27 for each quarter 2018 and I just wanted to confirm that for the fourth quarter are you – in your inherent guidance are you contemplating some budget exhaustion, are you contemplating that kind of dynamic scheduling or would that be – will it be inherent in hitting the low end of that guidance range for the fourth quarter, just want to make sure that…?

Yes. That wide range is even met 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 would 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 have had some scheduling changes. We are more trying to explain why it was Q2 so much higher than Q1 and Q3 is going to be a little lower than Q2, it’s not changing. Market environment, it’s not changing demand for our fleet. It’s just simply a 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 both on pricing and budget is often scheduling front. I don’t think we will see dramatic things there, but we may see something and as you have said Jud, it’s too early to really know how schedule and budget stuff will unfold in Q4.

Okay. Thanks for that. And then 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 reopen or is kind of timing of that, is that particularly a year end type of negotiation is every quarter, how do we think about when you maybe susceptible to any type of pricing softness in the dedicated market, is that a 1Q ‘19 or help us to think about that please?

Some of the arrangements are pricing fixed for the year. We have a number of those, but they would still be a minority of the fleets. Most often, there are just pricing agreements and we march forward in dialogue with our customers. If oil prices drop $30, we are going to talk quickly and if oil prices bump up $30 we will talk pretty quickly too. So they are 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 a quarter or a third of the fleets.

Okay, great. Thanks. And then if I can add – squeeze in one more. The new build over the next couple of fleets, some of your competitors are scrapping plans to reactivate or pushing things out and you guys seem to have pretty high level of confidence that the two fleets will start in the fourth quarter and the first quarter, could you give us some insight stuff you are close to securing contracts, how do you think about that?

Wait, I didn’t hear the last, but again Jud say that again.

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

We do. We are quite competent in that, the next fleet what we fleet 23. Yes, we 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 are in dialogues, I think given the market softness and all that we will probably almost certainly now I would say place that fleet in the Rockies, lots of demand for that. We are kind of sorting out who gets that fleet and then that will tie together what plans we had – we may have for fleet expansion in 2019 as well. But no, we are not worried about deploying both of those fleets into dedicated arrangements at good profitability for us and great throughput and economics for our customers.

Great. Thanks guys. I will turn it back.

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

Yes. Thanks. Just wondering if we could build on that conversation a little bit, so obviously you have got a very large Rockies operation, one of the debates seems to me is whether or not other basins will accelerate if the Permian softened somewhat, so can you talk about the demand indications in the Rockies and Eagle Ford and sort of what you are expecting as we move into 2019 here?

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 are Permian operators and they don’t have operations of scale in other basins. So I think you will 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 dapple pipeline in there that the differential between crude price realization in the Bakken and WTI is pretty low, that differential is small. So the drilling economics are superb in the Bakken. So I think the activity increase and activity next year in the Bakken is not so Permian related, it’s just hey we have got great drilling economics, we have got takeaway capacity, but 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 has been a lot of incremental supply coming out in the Permian, have you seen that in those other regions?

Not as much. There certainly has been new capacity added to the regions we are in, because if you look back 12 months 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 are a Tier 3 frac player and you are 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 will those fleets do over the 12 months or 18 months, the majority of them moved to the Permian. Market in the Permian was just so tight and the extrapolation of well was going and activity level just up, up. So if you are 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 activity, so take the majority of the incremental – the vast majority of the incremental frac capacity is on the Permian. But there has been fleet – re-valid fleets in all of our basins. So I think it’s not that there has 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 have had – we are having sort of the – plateau is even probably too negative of a word, but we are having a slowing wing 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 will get the market softness we are seeing and may see for one to three quarters in the Permian.

It makes sense. Thanks a lot.

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

Good morning guys.

Good morning George. Thanks for joining us.

Thanks for letting me on. On the efficiency front, obviously an awesome quarter for you guys, I wonder if you can just dig in a little bit more there and maybe talk about that maybe 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 how much more efficient you are 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 I think off the top of my head, I think it was 18% right it 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 would say in round numbers. You saw an increase, now a lot of the problems in Q1 we are walking on as cold weather water supply or customers can’t deliver water, we can’t frac, so we don’t have any of those problems. We have sort of a flat level, I know we don’t share the details of the number, because they also change and 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 base of the customer and type of work. But in Q1 all of those exogenous factors drove that down below really the low end of what we think the normal range, but we get why it happened. And then in Q2 we just had great lineups, but we I think in 2012 our first year in business we exceeded $118 million in revenue per frac fleet. Really a single frac fleet, but pricing was dramatically higher. But 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 frac world that’s supply-demand dynamics. But the thing that really aligns us with our customers is that we can get more done faster. It helps our profitability to get lower their well costs and gives them greater certainty and bringing production online. But certainly the highest throughput and efficiency we have 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 that they are not wildly out of the ordinary, but a little bit exacerbated scheduling challenges which just mean gaps between finishing one pad and moving to another pad that we are experiencing in Q3.

Okay, great, that was super helpful color, a damn good quarter. You actually entered into my second question and that answer, so I will pass to mic to somebody else.

Thanks for that George. I would hope you will appreciate the comment.

[Operator Instructions] Today’s next question comes from Jon Hunter with Cowen. Please go ahead.

Hi, good morning and thanks for taking my questions. So first one is you mentioned upgrading the blunder designs with the newest technology on about half of 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 have always been focused on collecting a significant amount of data around failure points and so we have done a lot of work on the blunders specifically in 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 have made significant steps forward without a significant investment of capital on each of those blunders.

The investments really in the design, engineering, the gathering of data, the testing, but we are 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 is significant, if you had to fix your car, but our business in capital deployment of the business, not meaningful.

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

You bet. Look, Ron and I and most of our team are career techners, I am an electrical engineer by training. So we have looked electric frac fleet really since we started the company. And we watch that technology and it’s intriguing. To-date that 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 that significant noise reduction, but the noise level of our acquired fleets is pretty much right in line with an electric frac fleet, so we 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, right it’s cheaper and in the field sometimes you have got it available. So we have addressed that with these dual fuel fleets. We have a number of dual fuel fleets today. And for a Tier 2 engine when you would run it 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 burned 89% natural gas and 11% diesel. So we can get 90% of the fuel 89% of the fuel switching savings, the same noise profile and a dramatically lower cost for us and our customers today that’s been a better trade-off. The other issue is gas supply, it’s not just the gas flowing out of the nearby well on the path, right you need several million MCF a day, several to run a frac fleet on that. So with the dual fuel fleet, if you have problems with gas supply, just increased the diesel content, you still got this robustness. We have an electric frac fleet. If you lose your natural gas supply, you are 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 have got large infrastructure, you are in the middle, you have got a gathering system and reliable supplies in natural gas, absolutely, you can do it, but it’s still a significant minority of the available well to frac and the fuel consumption and economic benefits aren’t there yet, but the technologies evolve and we are watching them. And as they evolve better, might Liberty have electric frac fleets down the road, very possible, very possible. We are constantly watching that. We love new technology as you probably can guess.

Yes, absolutely. And that’s some great color. So thank you. I will turn it back.

So, ladies and gentlemen, this concludes our question-and-answer session. I would 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 enable 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 number one, 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 have also seen a dramatic drop in global extreme poverty meaning living on less than $2 a day in today’s dollars. When the 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.