ProPetro Holding Corp (PUMP) 2018 Q3 法說會逐字稿

Good day and welcome to the ProPetro Third Quarter 2018 Earnings Conference Call. (Operator Instructions)

I would now like to turn the conference over to Sam Sledge, Director of Investor Relations. Please go ahead.

Thanks, Alison, and good morning, everyone. We appreciate your participation on today's call. As in the past, with me today are Chief Executive Officer, Dale Redman; and Chief Financial Officer, Jeff Smith. Yesterday afternoon, we released our earnings announcement for the third quarter ended September 30, 2018, which is available on our website at www.propetroservices.com. In addition, this morning, we posted a presentation on our website that summarizes our results.

Please note that any comments we make on today's call regarding projections or our expectations for future events are forward-looking statements covered by the Private Securities Litigation Reform Act. Forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. These risks and uncertainties can cause actual results to differ materially from our current expectations. We advise listeners to review our earnings release and the risk factors discussed in our filings with the SEC.

Also, during today's call we will reference certain non-GAAP financial measures. Reconciliations of these non-GAAP measures to the most directly comparable GAAP measures are included in our earnings release. Finally, after our prepared remarks, we will answer any questions you may have.

So with that, I'll turn the call over to Dale.

Thanks, Sam, and good morning, everyone. We appreciate you joining us for today's call. Building on what has been arguably the best year in ProPetro's 13-year history, we're pleased to report yet another strong quarter both operationally and financially. In the past 18 months, our company has more than doubled our fleet capacity. Even more important, during this period of strong expansion, we continued to keep the needs of our customers front and center by maintaining and, in many aspects, improving our best-in-class performance. During the third quarter, we continued to excel for our customers at the well site and our team's efforts are reflected on our outstanding financial results for the period.

While Jeff will go into more detail in a bit, I would like to provide just a few high-level highlights for the third quarter. We generated total revenue of $434 million. We posted net income of $46.1 million or $0.53 per diluted share, which was 18% higher than the $39.1 million or $0.45 per diluted share for the second quarter of 2018. And we grew adjusted EBITDA by 8% from the second quarter to $103.4 million, which was a record level for the company.

As we have discussed over the past year, we fully expect that 2018 would be a year in which well site performance and efficiencies and being responsive to the needs of customers would begin to truly differentiate pressure pumping companies from one another. These characteristics are how we have done business since Day 1. So they are ingrained in our thinking and culture. As I have said in the past, it's part of our DNA.

Our differentiated customer-centric business model was on full display in the third quarter as our performance was unsurpassed in the industry. Continued transition to pad development or manufacturing mode drove another period of increased zipper work. And as a result, we saw high operational efficiencies during the period. We also saw a rapid increase in the use of West Texas regional sand by our customers as 57% of our sand pump buyer fleets was sourced locally as compared to 35% in the second quarter. With even more regional and sand production coming online over the coming months, we expect this percentage to increase well beyond third quarter levels as we take delivery on additional contracted volumes along with growing customer adoption of local sand. The transition to regional source sand also allows us to drive increased operational efficiencies for our customers as sourcing product closer to the well site immensely improved supply chain and related logistics.

Turning our attention to fleet capacity. Our average active fleet count during the quarter was 19 fleets or 860,000 horsepower, all of which remain fully deployed and highly utilized. Early last month, we deployed our 20th frac fleet, bringing our current active capacity to 905,000 horsepower. This fleet is working with a new customer under a long-term dedicated agreement.

Looking at our cementing service operations, during the third quarter, we deployed 1 newbuild unit, which brings our total fleet size to 19 units. Later this year, we plan to build an additional unit and continue to see substantial opportunities for growth in our cementing services and coiled tubing services during 2019.

I will now turn it over to Jeff to discuss our detailed third quarter financial results. Jeff?

Thanks, Dale, and good morning, everyone. Looking at our sequential results for the third quarter as compared to the second quarter of 2018, revenue fell approximately 5.6% to $434 million from $459.9 million in the second quarter. Contributing to the decrease was the increased adoption of cheaper regional sand compared to the prior quarter, leading to smaller ticket sizes.

During the third quarter of 2018, 97.1% of total revenue was associated with pressure pumping services, which was consistent with the second quarter of 2018. Cost of services, excluding depreciation and amortization, for the third quarter was $320.1 million as compared to $351.9 million for the preceding quarter. The decrease was primarily due to local cheaper sand volumes and the related savings.

As a percentage of pressure pumping segment revenues, third quarter pressure pumping cost of services fell to 74% from 77% in the second quarter. General and administrative expense was $12.8 million as compared to $14.2 million in the second quarter of 2018. The decrease was primarily attributable to onetime expenses inflating SG&A in the prior quarter. General and administrative expense, exclusive of stock-based compensation and deferred IPO bonus, was $10.5 million or 2.4% of revenue for the third quarter of 2018.

Net income for the third quarter of 2018 totaled $46.3 million or $0.53 per diluted share versus $39.1 million or $0.45 per diluted share for the second quarter of 2018. Adjusted EBITDA increased approximately 8% to $103.4 million for the third quarter of 2018 from $96 million for the previous quarter.

Adjusted EBITDA margin for the third quarter of 2018 was approximately 24% as compared to the approximately 21% for the second quarter of 2018. The primary driver for this improved margin was the higher percentage of local sand pump of our total sand usage along with an increase in lower-priced contracted volumes available to us as compared to the second quarter.

Turning to the balance sheet and capital spending. We ended the third quarter with cash on hand of $78.2 million and total debt of $89.1 million. During the period, we incurred $74.2 million of capital expenditures, which primarily reflected spending on our growth initiatives and maintenance capital. Maintenance CapEx fell from the second quarter, but was still higher than we expected. The excess was partially driven by our high level of efficiencies and operational throughput during the quarter. We expect maintenance CapEx to continue to normalize in the fourth quarter based on continuing maintenance CapEx initiative instituted throughout this year.

Finally, total liquidity as of September 30 was $198.2 million, including $78.2 million in cash and $120 million of capacity under the ABL. While all possible shareholder return initiatives remain on the table, proceeds from near-term future cash generation will be prioritized towards debt repayment and to fund our previously announced growth initiatives.

With that, I'll turn it back to Dale for his closing comments.

Thanks, Jeff. As we look to the remainder of this year and into 2019, we remain confident in our ability to exceed customer expectations while keeping our frac fleet fully deployed. Our differentiated operating model is squarely focused on providing our customers unsurpassed near- and long-term performance, which has served us well over the years. We believe this will continue to set us apart in the current environment and through cycles.

During the third quarter, we once again saw outstanding operating efficiencies across our fleets. While this was clearly welcomed and a huge testament to the collaborative efforts of our team and customers, achieving these same levels of utilization and efficiencies will be challenging, given the typical seasonality due to weather and holiday downtime in the fourth quarter.

As we look at the broader industry, it is clear to see that the Permian is the premier resource play in North America, and we believe it will remain one of the most active regions in the world for decades to come. And with 100% of our frac operations focused on the Permian and our longstanding relationships in the region, we're in a great position to capitalize on long-term opportunities. Through the lens of our work here in the Permian, we have seen some remarkable transitions over the past several years. This includes a material increase in pad development, lateral lengths, completion volumes and working days, all of which have produced new and different challenges for pressure pumpers.

All that said, we could not be more proud of how our team has navigated and quickly adapted to operating in the new normal of manufacturing mode. We look forward to their continued innovation as we proactively address the evolving needs of our workforce and blue-chip customer base in a manner that will allow us to quantifiably show our value proposition to all current and prospective ProPetro stakeholders.

Structural change to the playing field is here, and it is real. This means that the players that are willing to partner and collaborate up and down the value chain to drive consistent returns for all involved will be successful, and we are proud to be leading the way in these efforts.

We will now open it up for questions. Operator?

(Operator Instructions) Our first question today will come from Tommy Moll of Stephens.

So Q3 looks good. Across the board, you've got record EBITDA per fleet, full utilization versus the industry trends, which were trending in the opposite and downward direction here. How much of your outperformance do you chalk up to your customer base being less impacted versus maybe your customers did slow their overall program and you all just made sure to be the last crew standing when cuts were made to the roster?

Tommy, there are several things in your questions. I'll touch on a couple of them. You've heard our narrative Day 1. I'll reiterate -- it reiterate it again, your customers matter. The other part of that is the collaborative effort that we talk about. We pride ourself in being in sync with whatever challenges that they’re faced with. And I believe our team on a day-to-date basis is doing a fantastic job of listening to what those challenges are in front of our customers. And we pride ourself on working for those people that in the best position for this manufacturing mode and that's really at the heart of how we built the company and how we've aligned ourself with those customers.

Got it. As a follow-up, I wanted to touch on the local sand trends that you guys are seeing. Clearly, the adoption there is growing quarter-over-quarter and it sounds like it will continue to. Do you see the -- from the operator perspective where the cost on sand is coming down pretty quickly? Does that mean that there may be more room to go in terms of the proppant load? We were potentially in the late innings under the old regime, where they had grown for a few years running. But now that the cost of that sand is coming down so quickly, is there another leg here?

Yes, I think it's flat quarter-over-quarter, but I think what I would say that's going to be dependent upon how that company uses that savings on their well cost and that's going to be different with -- in between those particular E&P companies. So I would not probably want to assume anything on that front. They will either drill more wells with that savings, return capital or load more sand. I guess that's how I would answer that.

The next question will come from Praveen Narra of Raymond James.

I guess, as we think about 4Q18 and then I guess into 2019, 2019 obviously look exciting, but a lot of your peers and some customers are talking about pulling back on 4Q18. I guess, can you help us kind of identify kind of a magnitude for what you're expecting for 4Q? And then more importantly, as we think about 2019, what your customers talking about, when they're starting to go back to work and then to what kind of degree you expect to see that improvement?

Yes. Each customer will navigate through Q4 based upon their particular situation. I think some of our peers have said in their quarterly calls that they're going to try to stay disciplined within free cash flow. Those that are in that position that are in our portfolio of customers will work with them seamlessly to make sure they meet their goals and keep that impact to a minimal on our side. Four things as we look at what we'll be dealing with in Q4, the normal seasonality with holidays, weather, we expect 1 or 2 points from a utilization standpoint. And then the budget constraints that you brought up, that should be minimal. And that's how we're looking at it.

So as we see this going into 2019, some of your customers indicated some growth in activity. Can you talk about how you think about capital allocation for next year, whether it is, you mentioned you're doing cementing, but also on the frac side for '19 versus potentially doing some sort of share buyback or return of capital?

Praveen, I can tell you that's a topic here on a weekly basis. And just, I know we sound like a broken record, but all those options are on the table. We are discussing all of those with the plan for 2019, probably not ready to announce anything today.

And one last one for me, just on the efficiencies. Can you just give us an update on zipper frac percentages and maybe stages uplift quarter-over-quarter?

Yes. Zipper frac, quarter-over-quarter went from 74% in Q2 to 84% in Q3. Total stages pumped was actually up 2%.

Our next question will come from George O'Leary of Tudor, Pickering, Holt & Co.

Following on to Praveen's question, and I appreciate the color on zipper fracs and stages, you guys have also talked about hours pumped being a key metric to watch. So just curious where you sit on an hours pumped per day, per month basis, however you guys frame it and how that trended quarter-over-quarter to get a gauge. I understand some of your fleets -- more of their fleets are operating in the Delaware and that's a little bit of a different animal. So maybe stepping back from stages and thinking about hours, any color there would be super helpful.

It was up just slightly quarter-over-quarter from Q2 to Q3.

And then you mentioned the maintenance CapEx initiatives that you guys have put in place, you talked about those a little bit. But what specifically are you guys focused on to reduce maintenance CapEx levels, is it mostly just the things on the consumable side, like valves and seats, fluid ends or is it more broad than that?

Well, I think it's broad as far as trying to affect all the component parts of these pump trailers. Obviously, the highest emphasis that we've got is on the fluid ends side of the equation. So, I can tell you that if you look at our numbers that were in the release, that loss on sale that as you guys have found and does relate primarily to fluid ends was actually down directionally quarter-over-quarter by about 14%. I can tell you the total maintenance CapEx quarter-over-quarter from Q2 to Q3 was actually down 10% in absolute dollars. So directionally, it's heading exactly where we guided to on the Q2 call. Q2 was something of a spike, it's heading in the right direction. I can tell you, it's pretty early in Q4 yet to draw any conclusions but the evidence we have thus far, we believe, that that trend will continue through the end of 2018. With all that said, historically, we have guided to the idea that maintenance CapEx should be projected for us somewhere in the neighborhood of 6% of revenue, and that's with normalized pricing. With the effect of regional sand on our top line, you really kind of have a new normal. And based upon being driven by that significant change to our top line with the regional sand, and in addition to that the intensity of the work that we're working right now, we will probably change our guidance, just up from that 6% of revenue to 7% of revenue on a prospective basis. And I can tell you that for total year 2018, the number should come in just a tick above that 7% number. But prospectively, that's how I would forecast it.

Great. That's a super helpful detail. The cementing side of the business is an area you guys keep making just kind of incremental investments. And Dale, I wonder if you could talk about that market a little bit and what you are seeing on the cementing side, given that's more of a related -- tied to well count, but it's more of a well construction oriented business, where are you seeing from an activity, from a pricing standpoint? And then, maybe could you frame the relative size of the cementing revenues within that pressure pumping segment?

I'll let Jeff size the revenue in that segment. I'll speak a little bit to the business itself. It's really, really strong, the demand's strong, rig activity as everybody sees, is still strong. And we try to have the same type operating prowess there in that space that nobody's waiting on (inaudible) locations and rigs that we're serving. So, we just see a very clear path to continue to organically grow that business at payback metrics that are better than our frac fleets, and margins that are a little better as well. But really good team, really good customers, same methodology in that space.

As far as the payback metrics on those incremental cementing units, we're probably generating about $500,000 of additional revenue per month out of each one of those units at 25% to 30% margins, which equates to a payback with sub-2 years, probably 18 months to 24 months.

The next question will come from James Wicklund of Credit Suisse.

I'm reminded of a saying, it ain't bragging if it's true. And you guys have definitely delivered in the face of a great deal of skepticism and so on that, congratulations. You did a great job of -- in terms of margin. I'm wondering -- we keep hearing about other pressure pumping spreads getting light down. Obviously, spot pricing is down from where it was couple of quarters ago. Does the overall slowdown and spot price pressure caused any of your customers to try and re-negate your pricing down or they try to get in the other economic concessions from you? Has there been any follow-through, if you would, on the industry slowdown and reduction in EBITDA per spread per year or however, whatever metric you want to use? Have you seen that in your customer base or are you that insulated from it?

Jim, great question. Very confusing for all involved in this space. I guess, there's a lot of ways to answer that. Performance and efficiency on location Trump's price. And my point there, there has been softness in some areas. This customer base we have, I mean, you know the acreage position, you know what they've done, and these folks are going to be disciplined, and they're going to develop that acreage, and they're moving to manufacturing mode. If you're making their well economics then you've heard me talk about well being in line with the well economics of our customers. We're constantly making sure we're within those well economics. And if you look at how we methodically priced our work through the recovery, we've been very transparent. And the payback metrics we've got to have to take care of this equipment and keep the best people on location, I don't know how we can be more clear with how we've planned and developed and built this platform and I think it's going to continue. 2018 is going to be over soon. I think everybody in the industry knows 2019, it's going to be a very, very busy and exciting year. And the guys that are looking at these acreage positions in developing over the next decades, they're looking at this much different, and they're partnering and teaming up with people that are going to be here and plan their business to be here for that time frame. So, that may not have answered your question, but that's how we're viewing this situation.

Well, the reality is the reality. And so, that was actually a very good explanation. So, I appreciate it. My follow-up, if I could, the relationships you have with your customers are obviously very good. The customers you're working for are obviously pretty big. They have operations in places other than the Permian. Is the customer contact a different one? Is the contact in oil coming not high enough, what stopped you so far? I mean taking your Permian business model, why don't you get dragged by some of your better customers to other basins to work as good as you are? If it was me and you were doing this kind of a bang-up job for me in the Permian, I'd be real tempted to take up to the Bakken and have you show people up there how to do it as well. Why doesn't that happen?

First of all, look at the customer base, and who we serve, and where they have acreage positions in other places. So, there's probably not many that are operating outside this base. And the other thing I would say, Jim, there's not a better place to do what we do than here. And the reason we are getting the results we're getting quarter-over-quarter and being able to build the platform and manage our business is because of where we're focused right now. There will be a time. We have no doubt, we can go anywhere and perform this work. That's not the issue. It's just the fact we've still got a lot to do here, and a lot of build out here, and we want to win here, every day. So, nothing precludes us from going anywhere in the world.

But why leave your backyard if it's not finished yet? I understand. And if I could, one follow-up, I know you haven't set budgets for '19 yet, but you talk about it being a busier year. We all expect it to definitely be a busy second half of the year at least. Can you give us a broad idea of what the preliminary discussion might be about how much additional horsepower you could, or should, or will put back to work through 2019?

Yes and we can't really give you guidance on that. I can tell you we're having discussions and have been discussions -- in discussions for several months. And those budgets are coming together with our customers. We're going to try to provide what we can, but I think it's too early to talk about that. Are there a lot of opportunities for growth? Yes. Are we going to stay disciplined and use our balance sheet as the throttle as we have this whole time? Yes. But we're not giving guidance to adding any capacity at this time. But there will be a lot of opportunity for growth in '19.

(Operator Instructions) Our next question will come from John Daniel of Simmons Energy.

On 2019, are your existing customers asking for incremental fleet next year?

We have enough visibility. There will be added needs to our existing customer base.

Do you anticipate that those added needs? Or are you displacing one of your lesser performing peers? Or they're expanding their operations?

I think it's probably a combination. But if you look at what's happened within our customer base, there has been some pretty good sized acquisitions. So it will be a combination of all the above from a growth opportunity.

Okay, sounds good. And then just to help better manage expectations for Q4, not that it really matters that much, but I think you said you might have a loss of 1 to 2 percentage points on utilization. That doesn't sound like very much given the holiday impacts, et cetera. Can you just -- is that right, only 1% to 2% on utilization?

Yes, just to clarify that, I think that what we lost -- and even in Q3, I can tell you we lost a point or 2 of utilization based upon primarily us run up the back of the drilling rigs. So the frac efficiency factor that a lot of people have talked about, it did affect us even slightly in Q3. We would expect that probably to continue into Q4. And then you would probably layer on top of that the normal seasonal effects of holiday time and weather.

Our next question will come from Chase Mulvehill of Bank of America Merrill Lynch.

I guess, to follow up on JD's question. If we think about utilization, you said, you know a couple of points hit the utilization, that didn't sound like a lot, but you kind of quantified that. I don't know, could you maybe translate that into stage count. If I look at my model that kind of says more or less flattish stage count given you've got a fleet coming in, the fleet that came in October. So help me understand and translate that into stage count?

Well, I mean, all I can tell you is Q3, we had a slight increase in total stages pumped and a slight increase in stages pumped per fleet. So I can tell you that -- what we probably would have expected, absent the effect of the frac fleet efficiency factor that I just talked about, we might have seen those actually increase even a little bit more. But that didn't transpire in Q3. In Q4, I would say it would be that same effect, but whatever you want to presume for seasonality of weather and holiday time, I will say holiday time this year contrary to last year, we're planning on being -- it will be down something that's comparable to our competitors, whereas last year we probably were down a little bit longer than our competitors. So I can't actually translate that into a specific numbers, but it won't be as dramatic as it was in 2017.

And then when we think about kind of revenue per stage in the fourth quarter, can you talk maybe about the moving pieces as you see it with sand versus, have you had any kind of renegotiations on price openers for some of your dedicated fleets. Just maybe some progression on revenue per stage in the fourth quarter would be helpful.

Well, the primary driver for revenue per stage in Q4 is going to be the -- a continuation of the effect that we had in Q3. On that we're anticipating pricing is going to be flat, but you're going to have the effect of even a higher percentage of regional sand affecting that top line. We were 57% in Q3. Not exactly sure where that number is going to go to in Q4. The one thing we do know is it's going to go higher than 57%. So you're going to get the continuing effect of that. If you had a fleet that was a 100% Northern White sand in the previous quarter and switches to a 100% regional sand in the next quarter, sand, in normalized pricing with Northern White, was 30% to 35% of our ticket. You're talking about using sand now that is 50% to 60% less in cost. So that in theory would translate to a 15% to 20% effect at the top line in a case where you want a 100% change from Northern White to regional.

And then zipper fracs in the fourth quarter, they were really strong in the third quarter. Are you seeing anything so far in October and early November that would indicate that your zipper frac mix would slide lower in the fourth quarter?

No. We would anticipate it to be relatively flat for Q4 over Q3.

And then, as we translate all this and think about your pressure pumping EBITDA per fleet, what's your outlook for the fourth quarter for EBITDA per fleet. I mean is it flat, down, up?

Given the effects of seasonality, we would suspect that it would be down slightly.

And the outlook for the loss on disposal in the fourth quarter?

I mean, I guess I would hope it would be somewhere in the comparable to what we had in Q3, maybe down a little bit if you end up with a little bit less activity based upon the seasonality of the quarter, you might expect it to be down slightly.

And then on same contracts. Do you have any sand contracts that cause you heartburn?

No. We worked very, very hard to contract enough sand where we feel confident that we have access to supply without locking ourselves into take or pay situations, and at the same time, have enough leeway to take advantage of spot pricing, hopefully when it's in a downturn.

Last one and I'll turn it back over. On the maintenance CapEx, you said it was down 10% in 3Q, what percent of revenues was maintenance CapEx in 3Q and then where do you expect this to fall in fourth quarter on the percentage of revenues?

We're changing our guidance to the 7% number. And I can tell you in Q3, it was probably just a tick above that 7%.

And of that tick above 7%, how much of that was fluid ends?

Fluid ends is typically about 50% of our maintenance CapEx number.

Our next question will come from Blake Gendron of Wolfe Research.

Just wanted to hone in a little bit more on the R&M side of the story. It seems like we're going to see a lot of pull forward amongst your competitors, probably [aptly] time before somebody blow somebody up I guess. When you think about your operations, specifically in the Delaware, we've heard within basin, pressure pumpers are rotating equipment as sort of backups that are basically a refurb or backup. Many crew they're just kind of rotates around pads. Is that how you guys view your operations set between Midland and Delaware? And then how does that impact, I guess, R&M and moving forward? Are you better able to maintenance this equipment in a predictive manner or you still pretty reactionary onsite?

I think, the same model that we've built the company with primarily in the Midland Basin, this is the same in the Delaware. And our approach to equipment is not any different than it's been historically.

And then, just talking about the efficiencies, you mentioned running into rigs. Your customers tend not build up [ducts] all that much, which seems to be a tailwind as the market softens here in the year-end. But as you think about the risks to efficiency in 2019 as we move into development mode, how do you frame the conversation with your customers to mitigate some of the risk of potentially running back into the rigs, or is the demand in 2019 going to be such that you can just find spot work in between your main customers getting their pads ready.

Yes, Blake, I think the people that we work for, they're so efficient and have done such a great job on the drilling side, that's not a concern for ProPetro with the customer base we serve. To the extent, I've mentioned in Q3, we probably had a little bit of an effect of that. But to this to date anyway, what we've been able to do is either find spot work for some of that equipment if it's down based upon that or we've been able to reallocate some of those fleets amongst our existing customer base that may need a little bit of help to fill in.

And then the last one, could you just remind us what the split is between the Delaware and Midland? And then, you go into growth mode again in 2019, how do you think about adequate scale with respect to those 2 subbasins?

Obviously, we've got 15 or 16 in the Midland and 4 in the Delaware presently. How that plays out over time will be dictated by the customers that we serve and how they allocate assets to develop that acreage position. And that's how we'll continue to run the business. Obviously, you can see the growth opportunity that I've talked about since becoming public of how we can scale this and the opportunity that exist out there to expand the size of the company. Growth is not an issue going forward for PUMP.

(Operator Instructions) Our next question will come from Ken Sill of SunTrust.

I know how hard it is to do what you guys are doing. So, it's pretty impressive. So, one question on the guidance. You said it's not going to be as bad as last year. Last year, you had a pretty significant drop in EBITDA per fleet sequentially. So, a couple of points down a little bit -- revenue lower on lower sand, definitely maybe -- I mean, I'm assuming, we're talking about 4 or 5 days off for holidays. What -- we're talking about a couple of hundred thousand of EBITDA per quarter drop sequentially or -- you seem not as bad as last year, which was more like $600,000, $700,000?

Yes, I think what we were talking about. We just -- we don't, but plan on having much vacation time that we extended because of what our people had done last year, and what it rewarded them. And looking at how the holidays land this year a little different. And we've been a little more collaborative with our customers, Ken. So, it's very fluid to guest. We're off to a really strong Q4 and excited about it, and we'll deal with those things as they come.

Hopefully, people won't care about Q4 anyway because that looks much better. So, we've got this temporary law and everybody's debating how fast things are going to come back. Is this having any impact on China equipment suppliers in terms of -- if you were to go, try to add some capacity, are lead time shorter than they were, or are we still looking at 5 to 6 months to build and crew up a fleet, when -- if you go back to...

Ken, I think that still holds true with our supplier. And that's -- we wouldn't probably move from that 5- to 6-month time frame.

Okay. So, where we are today, it'd be more -- you're looking -- if things are getting better, you probably wouldn't model that it until Q3 or late Q2?

Yes, that's fair.

Our next question will come from Kurt Hallead of RBC.

So, I'm kind of curious, as we head into 2019, and as you guys have your discussions with your customer base. What are the Top 3 hot-button topics that your customers have, maybe in general, but then, more specifically, as it relates to their expectations for vendor performance or frac performance going into next year? And if I were to ask for maybe one extension to that would be, how have those hot-button topics evolved and changed?

Kurt, the collaborative efforts we have with our customers have not changed. The question is, when can you get it here, if we need it? And that's about the extent of those conversations.

So, there is no other dynamics? We got to get crack and we got a lot of stuff to do. We need somebody who is going to be able to get here when they say they're going to get here and get the job done and be reliable. So, there's been really no shifts at all in what the E&P companies are expecting from their vendors?

No. To us, specifically, no change in narrative.

So, you referenced a couple of different times on answers to varying questions so far that growth is not an issue for PUMP going into next year, and obviously, not committing to any kind of fleet expansion or anything along those lines. And I can respect that and understand that. But beyond the fleet expansion, growth would have to go through M&A or unless you think that there is more that can be squeezed from your current fleet dynamic. So, just wondering if you can kind of maybe put some of that in context, is there more that can be squeezed from a utilization standpoint from your current assets that could drive growth?

Maybe a little bit, and then, that comes in at zipper fracs being at 84%. We still have room to go there. That's probably where that can move to. Obviously, 90%-plus gets us more of that squeezes some out as you have put. And that's...

One maybe for Jeff. Jeff, you provided some really good color on the sand dynamics and the impact on revenue as it relates. How should we think about the flow through on EBITDA or operating income as it relates to this mix shift on frac sand? What's the ultimate impact at that level for PUMP?

A lot of the benefit we got going from Q2 to Q3 had to do with a lot more of our contracted sand coming online. The contracted sand is at a lower price than what spot price was certainly back in Q2. That coupled with spot pricing itself actually declining substantially in the last several months, all contributed to that margin growth that we had in Q3. I would say, given that the average price we paid for regional sand in Q3, there's probably still a little bit more room to go on that benefit, but it won't be nearly the trajectory of the impact you saw from Q2 to Q3.

And then, maybe, one final one. I've been reading some material here lately. That was suggesting that the infrastructure dynamics in the Permian have improved and the ability to get around logistics and so on have improved. You guys live it, breathe it, every single day. I was wondering, if you can give us some updates on whether you're seeing an improvement in infrastructure and the ability to get from job to job?

We've never had much of that issue at all. So that we're not one of those that were probably struggling with that from a logistics standpoint. Obviously, it's a lot more active here, and there are a lot more people on the roads, and a lot of activity. But as far as affecting our ability to operate and do what we do, we're not having problems there.

Ladies and gentlemen, this will conclude our question-and-answer session. At this time, I'd like to turn the conference back over to Mr. Dale Redman for any closing remarks.

Thank you, ma'am. I just really want to express our sincere thanks to our people, our customers, our supply chain partners and our stakeholders for another great quarter, and appreciate your support, all your hard work and efforts, and have a good day.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.