RPC Inc (RES) 2018 Q3 法說會逐字稿

Good morning, and thank you for joining us for RPC, Inc.'s Third Quarter 2018 Financial Earnings Conference Call. Today's call will be hosted by Rick Hubbell, President and CEO; and Ben Palmer, Chief Financial Officer. Also present is Jim Landers, Vice President of Corporate Finance. (Operator Instructions) I would like to advise everyone that this conference is being recorded.

And Jim will now get us started by reading the forward-looking disclaimer.

Thank you, Riley, and good morning, everybody. Before we begin our call today, I want to remind you that in order to talk about our company, we're going to mention a few things that are not historical facts. Some of the statements that will be made on this call could be forward-looking in nature and reflect a number of known and unknown risks. I'd like to refer you to our press release issued today, along with our 2017 10-K and other public filings that outline those risks, all of which can be found on RPC's website at www.rpc.net.

In today's earnings release and conference call, we'll be referring to EBITDA, which is a non-GAAP measure of operating performance. RPC uses EBITDA as a measure of operating performance because it allows us to compare performance consistently over various periods without regard to changes in our capital structure. We are also required to use EBITDA to report compliance with financial covenants under our revolving credit facility. Our press release today and our website provide a reconciliation of EBITDA to net income, which is the nearest GAAP financial measure. Please review that disclosure if you're interested in seeing how it's calculated.

If you've not received our press release and would like one, please visit our website, again, at www.rpc.net for a copy.

I will now turn the call over to our President and CEO, Rick Hubbell.

Thank you, Jim. This morning, we issued our earnings press release for RPC's third quarter of 2018. The average U.S. domestic rig count during the third quarter of 2018 was 1,051, an 11.1% increase compared to the same period in 2017 and a 1.2% increase compared to the second quarter of 2018.

In contrast to the improvements in these industry metrics, RPC's third quarter 2018 revenues decreased due to lower activity levels and slightly lower pricing for our services. We began to experience weakness in the pricing for our pressure pumping services as additional horsepower continued to enter the market. In addition, pressure pumping efficiencies at the wellsite continued to improve, which has further contributed to overcapacity.

Our CFO, Ben Palmer, will review our financial results in more detail. After which, I will have a few closing comments.

Thank you, Rick. For the third quarter, revenues decreased to $440 million compared to $471 million in the prior year. Revenues decreased compared to the same period of the prior year due to lower activity levels and slightly lower pricing, primarily within our pressure pumping service line.

EBITDA for the third quarter was $97.8 million compared to $137.5 million for the same period last year. Operating profit for the quarter decreased to $54.6 million compared to $97.4 million in the prior year. Our diluted earnings per share were $0.23, including a $0.04 per share favorable discrete tax adjustment, compared to $0.26 in the prior year.

Cost of revenues during the third quarter was $300.9 million or 68.4% of revenues compared to $294.8 million or 62.6% of revenues during the same period last year. Cost of revenues increased primarily due to higher employment costs, partially offset by lower materials and supplies expenses, which declined due to lower activity levels, again, particularly within the pressure pumping service line. As a percentage of revenues, cost of revenues increased due to inconsistent activity levels and higher employment costs.

Selling, general and administrative expenses were $41.8 million in the third quarter compared to $39.7 million last year. As a percentage of revenues, these costs increased from 8.4% in the prior year to 9.5% due to lower revenues and the relatively fixed nature of these expenses during the short term.

Depreciation and amortization were $43 million during the third quarter of this year, an increase of 8.6% compared to $39.6 million in the prior year.

Our Technical Services segment revenues for the quarter decreased 7.6% compared to the third quarter of the prior year due to lower pressure pumping activity and pricing. Operating profit decreased to $56.2 million compared to $104.3 million in the prior year.

Our Support Services segment revenues for the quarter increased 22.5%, and operating profit improved to $1.8 million compared to an operating loss of $2.1 million in the same period last year.

On a sequential basis, RPC's third quarter revenues decreased to $440 million from $467.9 million in the second quarter. Revenues decreased due to lower activity levels from a lack of consistent work and slightly lower pricing.

Our operating profit during the third quarter of '18 was a $54.6 million compared to $75 million in the prior quarter.

Cost of revenues during the third quarter decreased by $11.1 million or 3.6%, primarily due to lower materials and supplies expenses and lower maintenance and repairs expense, partially offset by higher employment costs. As a percentage of revenues, cost of revenues increased 1.7 percentage points from 66.7% in the second quarter to 68.4% in the current quarter.

Selling, general and administrative expenses decreased by 1.8% compared to the prior quarter. RPC's EBITDA decreased from $119.2 million in the prior quarter to $97.8 million in the current quarter.

Our Technical Services segment revenues decreased by $28.6 million or 6.4% to $421.3 million in the third quarter. Operating profit was $56.2 million compared to $75.6 million in the prior quarter.

Our Support Services segment generated revenues in the third quarter of $18.7 million or 3.6% higher than the prior quarter. Again, operating profit was $1.8 million compared to $1.2 million in the prior quarter.

Third quarter 2018 capital expenditures were $49.9 million, and we expect our full year capital expenditures to be approximately $280 million.

At the end of the third quarter, our cash balance was $128.4 million, and we have no outstanding debt.

With that, I'll turn it back over to Rick for some closing remarks.

Ben, thank you. Despite $70 oil, our third quarter results reflected improved wellsite efficiencies and increased service intensity, but less than optimal utilization. This reduced our fixed cost leverage, and combined with increasingly competitive pricing in our pressure pumping service line, negatively impacted our profitability.

Yesterday, our Board of Directors approved a regular quarterly cash dividend of $0.10 per share and an additional $0.07 per share special year-end cash dividend. Year-to-date, RPC has spent $40.2 million on stock repurchases, paid out $64.6 million in dividends and invested $199.6 million in capital expenditures. Including these uses of cash, RPC ended the third quarter with $128.4 million in cash, $37.3 million more than at the end of 2017.

I'd like to thank you for joining us on the conference call this morning. And at this time, we'll open up the lines for your questions.

(Operator Instructions) And we'll take our first question from the Stephen Gengaro with Stifel.

I guess 2 things. You mentioned, obviously, the pressure pumping pricing environment that you're seeing, and we're hearing from others as far as the period. How should we think about the play between pricing and utilization as we kind of look at the next quarter or 2? And how are you guys sort of viewing operating assets versus -- and dealing with the white space in your calendar?

This is Ben. Good question. I mean, that's the fundamental question. I think we're trying to be -- continue to be, as we already -- always are, disciplined with pricing and trying to find that right balance. The work that's being done is very harsh on our equipment. So in some jobs, some areas are more difficult than others. So we're trying to seek that correct balance, but are trying to protect our equipment and protect pricing as much as we can. But that is a delicate balance that we're always striving for. Third quarter reflects that it wasn't perhaps where we would ideally like it to be, but the environment right now is very dynamic, and I think everybody's trying to search for that right combination. Of course, at this point going into the fourth quarter, there's a lot of -- there's uncertainty about the level of activity in the fourth quarter. We're expecting that all things being equal, we'll have some holiday slowdown impact. But again, we're striving for that right mix and looking forward to a better environment in 2019.

Would you be able to give us a rough idea of where current pricing is now versus where we were kind of on average in the third quarter?

Stephen, this is Jim. Let us answer it this way because right now, it's a little bit of an update for fourth quarter that we don't have in front of us. Pricing declined sequentially about 3% or so between second and third quarter. The larger catalyst for the revenue decline in pressure pumping was utilization. As Ben mentioned, our wellsite productivity is very high, but there was white space in the calendar for various operational reasons that happened on a completion wellsite. So those were the 2 main catalysts for the revenue decline. But the larger 1, the larger of those 2, was utilization rather than pricing.

And we'll take our next question from Chase Mulvehill with Bank of America Merrill Lynch.

I guess maybe if you could shed some light on your 4Q outlook. I mean, obviously you've got some budget constraints and pipeline capacity issues that are going to be impacting the completion market. [I don't know,] any color on the top line and then maybe some incrementals? I mean, is it fair to assume that top line will be down double digits? And then it looks like historically, decrementals have been, kind of through the downturn, about 45% to 50%. Is there any reason you think you'd kind of be outside of that range?

Well, I've already, I guess with my earlier comments, indicated that we would -- we are expecting some holiday slowdown. Certainly, we're trying to fill up the calendar as much as we can. But in terms of decrementals, I mean, there's a lot that goes into that. I don't want to comment on specific percentages. We're not making any significant adjustments at this moment. I mean, there are adjustments around the fringes, but we are -- we're not making any significant adjustments to the cost structure at this point because we are expecting improvements during '19 and beyond. Or that's, at least, our current thinking at this moment.

And Chase, this is Jim. The operational metrics that are visible to us through October look pretty good in terms of our activity levels. But we are cautious about Q4 because of what happened last year, and we encourage everybody else to remember it if we can. So there are holiday slowdowns; discussions about budget exhaustion; and this looming issue, which we have not seen yet, but the Permian takeaway capacity issue, all could combine to make fourth quarter low double-digit revenue declines, based on what we know now. But again, the big uncertainty is holidays and budgets that we will not know about probably for another 4 or 5 weeks.

Okay. And then if we think about utilization, obviously, it's kind of a utilization game as we go through this kind of soft spot. When do you -- when would you expect utilization to bottom? Would you think it's going to be kind of later this year? Or do you think utilization continues to sag into the first quarter? And so just any color on your fleet utilization as you go over the next couple of quarters.

Well, I think kind of alluded to it. We think there will be holiday slowdowns. And we think the first quarter will reflect some improvement, and there's some optimism around the first quarter. And it's always unclear about how quickly things bounce back after the holidays. Some years, it does; some years, it doesn't. Last year, it did take a little bit of a time for the traction to take hold in early '18. So I wouldn't be surprised either way. We can't do a whole lot of planning around that kind of thing in the short term, but just realizing that it could occur and doing everything we can to fill up the calendar as much as we can, given the dynamics that we're working with.

Okay. And it seems like you got a little bit more dedicated fleet exposure today. Now where does that sit today from a dedicated exposure?

Chase, this is Jim. It's between 55% and 60%, to give a precise number. A little over 1/2 our fleets are dedicated at this time.

Okay, nice job on that. And the last one, I'll turn it back over. You're doing a special dividend. I think there may have been a small slither of buybacks during the quarter. Why a dividend versus buyback? And then how does M&A fit into your capital allocation strategy?

Well, we have -- we certainly have the balance sheet to do a lot of different things, and we plan to take advantage of that. We're going to -- we've always focused on shareholder returns and are managing our capital well and will continue to do that. We did not have any share repurchases in the fourth (sic) [third] quarter, and we kind of have -- we've developed a streak of paying a year-end special dividend, and we're proud of that and we think that's a good reward to our shareholders. And we'll continue to try to seek that right balance between investments in the business, shareholder -- share buybacks, dividends. And then on the M&A front, we're going to remain disciplined there. The prices are high and it's come to fruition that maybe some transactions that may have been at a big price, that comes with a lot of risks. So we'll continue to be particular about where and how we invest. And continue to believe that for us, historically, the best returns have come from organic growth and pursuing those kind of opportunities.

Love to hear more about capital discipline in this sector.

And we'll take over next question from Marc Bianchi with Cowen.

Just to clarify earlier on the comment about October. Are you saying October is better than where you were on an average in third quarter?

Marc, this is Jim. I didn't say that, I'm not sure that's true or not. It may be, we don't have all the metrics and we haven't closed the books for October. I'm just saying that October -- that was my comment, October is fairly strong. But I did want to emphasize that we didn't know about the Q4 slowdown last year until right around Thanksgiving. So that's what's makes a fourth quarter forecast, even though we're in fourth quarter right now, very difficult.

Sure, sure. Okay. Can you say what the percentage of the business lines was to revenue?

Sure, absolutely. Yes, absolutely. So the figures I'm about to give are for the third quarter of 2018 as a percentage of consolidated RPC revenues. So pressure pumping, again, our largest service line, at 54% of revenue. Our second-largest service line is our Thru Tubing Solutions business, and that was 25.2%. Coiled tubing was #3 at 6.0%. And rental tools, which is in Support Services, rental tools was 3.2% of consolidated revenues for the quarter.

Great. You guys mentioned the efficiency issue creating some slack. Can you help quantify what you're seeing there? And maybe talk about how much more efficiency we can expect, how much longer this could be kind of a headwind to the supply-demand balance?

Marc, this is Jim. It's -- again, it's hard to say. We actually, in the pressure pumping business, completed more stages in the third quarter than we did in the second quarter. But our utilization, measured in terms of days of activity, was lower. And so what that means, just in common vernacular, is that when we are working, we are working really hard and we're very efficient. But there were times when we finished a job too soon. And as you know, you know the business the way it is today, you might be finished 2 or 3 days early and you would then have labor costs and other costs that weren't generating revenue for you at the time. Now certainly, it's clear that if you're paid by stage, by pressure pumping stage, that doesn't necessarily impact revenue, but it certainly lowers your utilization. And that, coupled with some pricing, really kind of was the big catalyst. How much more efficient can we get? We don't know. We hope that the industry may kind of be approaching that point of diminishing margin returns, but we're not sure.

Of efficiency. This is Ben. Efficiency, as you know, can be measured in number of stages, right, we're executing a day. It can be measured with the amount of employment costs you need per fleet to execute a job, all -- and both of those things we're, of course, working on. It can also be defined as managing your logistics costs and your material cost. And all of those things, we're working on. And we've got a number of initiatives and programs that we're undergoing now to try to create more efficiencies for ourselves. I mean, there, a lot of the benefit is sort of around the fringes and things you realize over time. But we're looking at our maintenance processes, we're looking at our equipment configurations. We're updating our HR systems and processes. So there's a variety -- and all of that kind of relates to data. And there's other things we're doing to capture our data better and analyze our data to help with our operational efficiencies and also to make, of course, better management decisions. So those are things that are ongoing. Benefits, again, will come on the fringes and over time. But we do that to try to leverage our costs as much as possible. And we've been through this kind of period before, and we'll adapt just like we have in the past. We've got -- our management team has been through this many, many times, so we're confident we'll make the necessary adjustments and continue to perform well over time.

I just have one more. If -- and I know it's still early. But if you can provide any initial thought on 2019 CapEx and remind us kind of what the maintenance level typically is.

We're going through that process right now. Obviously, it's a critical decision point for us. We are going to continue to invest in our company in a variety of ways, but again, focused on total shareholder returns. But again, have not made the final decision. But it's...

It is fair to say that -- would you say that it's more likely CapEx is flat to down? Or more likely up from 2018?

No. At this point, I would probably say flat. Given where we are, we're going to continue to invest. We don't believe that in '18, we aggressively invested. And I think as we look back, that was probably the right decision. And I think at this point in time, I think I would say we're not going to aggressively invest, but we will continue to invest. I mean, the industry's not going anywhere, and we're going to take advantage of our balance sheet and continue to grow it over time and try to make the right decisions to invest in the right equipment and have everything in the right equipment configurations and that sort of thing. So at this point, I would say a similar investment is probably the most likely at this point in time.

And we'll take our next question from Praveen Narra with Raymond James.

Maybe if I can follow-up on Marc's question on the efficiency gains. Can you give the zipper frac percentage for 3Q? Did I miss it?

Praveen, this is Jim. Sure. We have it, and it is -- let me try to give you the right number. 67% of our pressure pumping work in third quarter was zipper compared to 60% in second quarter.

Okay, perfect. And then I guess if we could talk about the pricing question from the beginning. A lot of anecdotes out of some competitors talking about how competitive pricing is getting. As we go through the fourth quarter, it's clearly going to be weak. Can you talk about where the leading edge is? And I guess how it compares to your willingness to do the work versus turn it away. And I guess, if you could add on if operators are trying to use this as an attempt to sign contracts since pricing's pretty low.

Praveen, this is Jim again. If talk about leading edge, I mean, we know there are bids for work that are 15%, 20% lower than prices at which we're working. And we are not engaging in those. I mean, you know us. Our preference is to preserve pricing to the extent possible, even if it means sacrificing utilization. Part of that reason has to do with the service intensity of the work and how hard it is on the equipment. So that's -- you're hearing of bids that are a good bit lower than the prices at which we're operating today. Will customers try to sign -- get you to sign contracts in fourth quarter? I don't have any visibility into that. I don't -- we don't, not really.

And Jim alluded to it. This is Ben. Alluded to this. We're not going to chase pricing down to try to fill up the calendar for the fourth quarter. It's going to be a slow period, probably. And we're working hard to fill it up as much as we can. And looking forward to a better '19. So we don't want to chase the pricing down at this point in time. So we'll take whatever comes our way for the fourth quarter, knowing that it may be -- seasonally, typically, it's a little bit weaker. But again, we'll take advantage of our balance sheet to pursue -- continue to pursue the strategy that we've been talking about.

And I guess if I could clarify one thing on 4Q, and I don't think this reads a whole lot into 2019. But in terms of incremental margins or decremental margins to 4Q. As I think about labor being pretty high, I assume repair and maintenance is going be maybe a little bit higher than normal for 4Q. Is it fair to think that incrementals should be higher than 50%? I guess, just given the fact that it is a transitory pause. We'll recoup it in 2019, but I would think that 4Q should be a bit higher than normal.

Praveen, that's reasonable. I mean, as Ben has alluded to a couple of times, we are not going to lay people off because we have a slow 6 weeks. But if, in fact, we do, so, yes, that's reasonable.

And we'll take our next question from James Wicklund with Crédit Suisse.

And so what I'm hearing you say is that the efficiencies, rather than any Permian slowdown, is what dropped your pricing about 4% in the quarter. You're not going to drop down and sacrifice utilization -- or sacrifice pricing for utilization, and that's all good. Have you -- at the end of the quarter, you hadn't seen any Permian weakness. Here we are, the end of October, have you still not seen any Permian-related slowdown?

Well, we're -- Jim, this is Ben. We're -- certainly, industry-wide in what we read or hearing anecdotes about that. But I guess what we keep saying is our guys aren't saying, "We just got a call from our customer, and they said because of the Permian takeaway issue, we're slowing down right now." So I think...

Well, I don't -- I'm not talking about that explicitly, but I mean, we look at the frac spread count, and it's gone down, and so that means that fewer spreads are working, right? And so it just means you guys haven't lost any of the crews that have been lost, but other people have. Is that it?

Well, Jim, actually, this is Jim. That is correct, the people who've moved fleets...

Okay, that's why I'm asking.

Yes, the people who've moved fleets and various other things. I mean, I just want to emphasize the metrics we see through October, we are not seeing an activity decline right now. I do want to emphasize, though, we will be among the last to know. It's not in our customers' best interest to tell us when they are planning to slow down. So...

Well, I understand, but that's -- we're going to holiday period. At this point on the fundamental business, if you haven't seen a drop, then you picked the right clients to work for, it's my only point. Right?

Well, sure. We'll accept that.

Okay. I mean, At this point last year, you were at 95% utilization. To your point, nobody saw Q4, what happened to you guys. And we understand it can happen this year, but the fourth quarter is never a proxy for what happens next year anyway, right?

That's right.

Correct.

That's the way we view it. That's right.

Okay, okay. I'm just checking to make sure. Jim, you mentioned the stage count from Q2 to Q3. Could you give us the increase in the stage count? Can you give us the numbers?

I can -- we really don't do that, but I can -- we can talk around the percentage increase, Jim.

I'll do that, yes.

Yes. So between second quarter and third quarter for the total for the quarters, our stage count increased around 10%.

Okay, that's still significant. And while we understand that you all don't really give explicit guidance, and that's fine, and '19 is an unknown. There's a big wave of sentiment among investors that if the companies would just gave a bare-bones estimate of what they thought they could make if the world ended and have that be the consensus, then you could start having upward earnings revisions sooner...

Right. We could start...

And everything will work better. Yes. So I just thought I'd mention that in terms of you guys, when you see the consensus over the next couple of days, feel free to knock us down if we're too aggressive, okay?

Okay. Well, Jim, [definitely] the people on this call, all your peers, are too mature for that game. So we're just going to try to do our best.

Don't you wish that was true. I've got one company that operates -- their operation's in the Permian. They said they're looking at 10% to 15% labor cost inflation in '19. What are you guys factoring into your cost analysis for labor inflation for '19?

Per head? Not that level. It's probably mid- to upper single digits at this point. But we'll see. I mean, it remains competitive. And just like trying to fill up the white space in your calendar, trying to attract and retain employees is a struggle as well. So [we'll have that handicap].

Are we still doing man camps? Are your still -- are we still doing man camps and you're still circulating people out? Or has things settled down from the gold rush mentality?

Jim, I'll describe it this way. We have a number of apartments that we have for employees. And we have, at various times, moved people among different basins, specifically the 3 operational areas in Texas, and continue to and that sort of thing. So I wouldn't call it man camps, but we certainly have apartments leased for people to live temporarily, one place or another.

And we'll take our next question from George O'Leary with Tudor, Pickering, Holt & Co.

From a dedicated fleet perspective, given you guys have trended more in that direction in the last few quarters, opposed to being largely spot, how would you describe Q4 pricing on a dedicated fleet basis sequentially versus the third quarter? My understanding is you negotiate those in advance of the next quarter. So if spot bids are down 10% to 15%, maybe you don't play in that because pricing's too low. Can you speak to what you have agreed to playing on this 55-or-so-percent of your fleet that's dedicated for the fourth quarter?

George, this is Jim. It's -- that's hard to say. I mean, I will tell you that pricing has not changed, based on everything I know, but that's not much. These aren't -- these don't reset on October 1 and January 1. They come around whenever the previous agreement finished. I would say that, I mean, the bias is generally down, but we just don't have any specific information about what fourth quarter pricing looks like.

Fair enough. And then I think you guys seemed to imply in one of your earlier responses to a question that you kind of held the fleet count, in terms of active fleets working, is holding in all right. Just curious what the average fleet count was during this third quarter that was active, and what the exit rate was at the end of the third quarter.

Well, in terms of the fleet count, this is Ben, it did not change. In terms of active and inactive, I mean, there's a lot of different ways to define that. So a reasonable question, I guess. But I'm not sure I have that metric. But we are not operationally thinking about that we are either adding or decreasing fleets at this point or during the third quarter. So that's really the only way I guess I could answer it. Jim, do you have any? No?

No, no.

Fair enough. I'll sneak one more in, if I could, then on the selling. You're not making any adjustments to the workforce, there's anticipation of an increase in activity in the first quarter of '19, and we would agree with that. But there is some underlying level of attrition in your business. People exit the business fairly regularly. I imagine that's still happening, given how tight the labor market is more broadly. So you may not actively be making adjustments, but are there some costs that come out of the system just as people leave, and maybe you're not rehiring people to fill in those seats?

I bet there may be a little bit of that around the edges, but that's not a conscious decision that we're openly making right now. I mean, there may be some delays in hiring just because people aren't -- maybe the employees aren't as aggressively looking around the holidays. So I wouldn't doubt that maybe we exit at a slightly lower rate than we entered the fourth quarter, but that's not necessarily, again, a conscious out and out decision that we're making, to slow or to reduce the headcount.

And we'll take our next question from Tommy Moll with Stephens.

So you called out in the release that one of the drivers on pricing for the frac business was some additional horsepower entering the market in Q3. Was that limited to the Permian? Or did you see that in other basins as well? And can you generalize just in terms of who you were referencing there? Was it some larger public players? Midsized public players? Private?

It was -- Tommy, this is Jim. It was both ends of the barbell, the very largest and then the formerly smallest, who are now growing a good bit due to equity infusions. And it was -- and not completely sure, I think it was the Permian, the Midcontinent and probably the Bakken as well, some areas where there were more fleets put in. And also I think East Texas. So maybe it's a fairly broad-brush comment.

Okay. And we haven't talked about sand yet today, but in the space of 1 quarter, that market has changed pretty quickly. So I'd be interested to know, how much in-basin sand are you pumping now? And with pricing across all the grades coming down pretty quickly, is there a read-through to your profitability for frac in the next few quarters? Or it's just a straight pass-through, and there shouldn't be any impact to your bottom line there?

Yes. Tommy, this is Jim. That's a good question, thank you for it. During the third quarter, a little less than 10% of the natural sand we used came from in-basin, came from the Permian Basin mines. You're right that pricing has declined and availability has increased for just about everything that you want in terms of proppant. And also about 10% to 14% of our sequential revenue decline in pressure pumping was due to the fact that we were pumping in-basin sand, which is a lot cheaper. It is marked up. We do make a profit on it. But with that cost being lower, the markup, while the same, and the margins maybe were the same, that does serve to decrease revenue. Our customers are aware that the price of proppant is declining, and they expect some help with that, some benefit from that. But we do endeavor to always mark up everything so that we earn a reasonable profit and a reasonable return on capital. So that's the dynamic going on there. Who keeps what part of that additional economic grant is a reasonable question, but remains to be seen.

And we'll take our next question from Ken Sill with SunTrust Robinson Humphrey, Inc.

You may be on mute. Can't hear you. Are you there?

Can you hear me now?

Yes.

Yes. I had set that, I guess. I could hear you, but you couldn't hear me. So following up on the sand question. How much of your own sand did you guys use in Q3 versus Q2? And is there a change in that trend?

Yes. Let's see. Of our sand, I believe -- I think it was 64% of our sand.

It was down.

It was down. 70% to 64% or 63%, sequentially.

64%, 63%. So down about 5%, 6%. And is your price coming down with everybody else's or not as fast? Kind of hard to figure that one out.

Don't know. In other words, is the cost of our sand declining at a greater or lesser rate than...

Yes, your selling. Is your average selling price coming down like everybody else's?

We're selling to ourselves, so the cost is not changing. Per ton is not changing.

Yes. Okay. And then on the frac fleets, how many do you guys have outside of the Permian versus in the Permian?

Out of a total of 21 fleets, being 19 horizontal and 2 vertical, 11 are outside of the Permian.

And then that's a pretty big uptick in the number of fleets where you've got kind of dedicated arrangements, which I think helps. I mean, I just find it's interesting that everybody is finding a way to kind of miss our expectations, but they're doing it in different fashions. But with your dedicated fleets, everybody says 2019 is going to be a better year. How far out are your dedicated customers planning right now?

Ken, this is Jim. I know a customer and have been on their job sites, and we got a dedicated agreement with them in late September that goes for a year. If that answers your question. But let me answer it a little more fully. I want to make sure everybody understands this. Dedicated fleet arrangements today are not the contractual agreements of prior periods. If a customer slows down or has a job issue, whether it's our fault or another of the myriad service companies that are on the site, we do not get paid for that downtime. And so that is a reason that today's dedicated fleet is not an annuity of any sort.

I mean, it feels good to have that relationship and you're more likely than not, certainly, to work for that customer if you have that dedication. But it's not a guarantee of volume. It's not a guarantee of days on the wellsite. I mean, it is a relationship decision, and it's a relationship you're entering into, but it's not a firm dedication.

Yes. And that's, like -- I guess my question was digging at it a little bit deeper, is, for those guys, I know it's not firm, but how far out have they got their frac calendars planned right now? I mean, are they still only looking out to 45 to 90 days? Or are they talking about big jobs they've got that they're going to need next year yet? It being only October.

Probably more shorter term, Ken.

Okay. I mean, that makes sense. And then when you guys are talking to these dedicated guys, I mean, I'm listening to all the reporting so far and people are missing because their customers are shutting down in mid-November. You're not seeing that. Somebody else missed because their maintenance costs were higher than expected because they're zipper fracking. Well, okay, that's something you guys didn't have an issue with. I guess, my question for you. Your customers' coming back to you, with some of your peers that are doing these things that don't seem to make a lot of long-term sense, and pushing you on pricing without caring about whether you actually make enough money to keep providing your service.

Yes, absolutely.

Yes, so it's just -- until people...

Like any other competitive business, they are happy to present competing bids that are much lower than our current rates and ask us to match them. That is correct.

Well, I think you guys are doing a good job in an uncertain market, and I hope you're right about next year.

And we'll take over next question from John Daniel with Simmons & Company.

So if I've done my CapEx calculation correctly, it looks like Q4 is going to step up to about $80 million, ballpark. If that's correct, are you guys -- does the Q4 CapEx spend include any deposits for new equipment which will be delivered next year?

It does not, John. That involves some coil tubing CapEx and some snubbing CapEx.

Okay. And I assume that's more large-diameter units?

Yes, absolutely.

Can you walk us up there when you stand on the coil, large diameter, and sort of what you're doing there? In terms of number of units you have and -- or what's on order? Just any granularity.

Yes. John, I'll be honest. We don't have that right in front of us. We have very few large-diameter coil tubing units, and we need more. So.

Fair enough. Sort of -- I'm sure you've listened to some of your peers' earnings calls, but there's the narrative out there, which is next year, you get resolution of the Permian takeaway constraints. You get higher 2019 budgets and then you have the eventual wind down of the growing DUC inventory. And so collectively, all of that should lead to nirvana. And I'm wondering though, you call out the frac efficiencies, and there is still a modicum of new supply, there's still some new companies forming. I'm just curious if you think the efficiencies that we're seeing with frac is going to be the Achilles' heel which could dampen the recovery narrative. Just your thoughts.

Well, John, it'll continue to be an offset. But you do have -- hit a point of diminishing marginal returns. You can go from 4 hours a day to 8 to 12 to 22 hours a day of actually working on zipper fracs. But there are equipment failures and there's this incredibly complex coordination of all the different service providers on site, and so you can probably only be so efficient. So I think that there will probably be -- continue to be an offset. And we and others are using technology to do things better and differently. It'll continue to be an offset. But we love your scenario for 2019, but what's the price of oil going to be, too? So that's a level of uncertainty that we need to deal with.

Fair enough. As you look to the 2019 CapEx spend, and I know you don't want to give a specific number, which is totally fair. But as you think about investment in new equipment, the market clearly doesn't need new frac horsepower, right? We're oversupplied.

Right.

But we need better horsepower. So can you speak a little bit to what you might do to change up the equipment designs as you look to order equipment for next year? And then how quickly can you roll that through the entire fleet?

John, this is Ben. Good question. I mean, we've -- that the last couple of additions that we've done, we've tried to respond to that situation by ordering equipment that's higher horsepower, more suitable for the type of work, the high-intensity work that's taking place. So certainly, going forward, I think equipment that we order, more likely than not, the majority of what we would add when that time comes is going to be the higher horsepower and more robust components, that we'll be able to do the type of work that's taking place today. I think with the legacy fleet, the units that we have that are older, there are some opportunities we've been taking to put on more robust components to the extent we can. But there's still going to be a lot of work. It's competitive, but there's still going to be work that's not -- that the older equipment, that's say, that's 4, 5, 7, 8 years old, there's still going to be, I think, work and opportunities there for somebody who can keep their equipment maintained and work safely and efficiently. And I think there will be work there for that. I don't think we need to upgrade all our pumps.

Entirely?

That's right. That's right.

Fair enough. Okay. Last one for me, just sort of following Wicklund's questions about setting expectations. One, Jim, can you just talk about, I know October is a good month. Historically, it's always been a pretty good month, but we had some pretty heavy rains in the Permian. Can you address that impact? And then, two, just sort of throwing pasta against the wall here, low double-digit revenue decline potentially. Does EBITDA in Q4, does it potentially have a 6 handle on it? And then I'll turn it over to the next person.

John, I'll answer your -- let me address your second question first, which is low double-digit revenue decline sequentially, based on everything we know right now, are -- is feasible. I mean, it's very possible. EBITDA with a 6 handle? It would be -- I don't know. That's just hard to say right now. Then on your first question, so far, we haven't seen any issues in the Permian due to rain. With the duration of these jobs, once you're on site, you can stay even if it's raining. It's moving equipment that gets you in trouble if it's raining. So we haven't had any rain-related issues in October in the Permian.

And we'll take over next question from Dan Boyd with BMO Capital Markets.

Just another follow-up on CapEx. In the scenario of flat CapEx for next year, would that contemplate some additional equipment in the pressure pumping side? Or is that more just kind of additions outside of pumping and maintaining what you have?

This is Ben. I have said before and continue to say, we have not placed any orders for equipment at this point in time. But I think I said in last quarter or the last couple of quarters that I expect that we will take delivery of some new equipment in 2019.

Okay. So that's a bit in there. And then you commented on using your balance sheet. And I understand that, given the outlook for the second half of '19 and 2020 looks very good, but choppy waters in the near term. So does that imply that you're willing to draw down the cash balance or even use the revolver for some of that CapEx, at least for the first half of the year?

If necessary, sure.

Okay. And then last one just on the efficiency gains, because that's the big topic, I think, that's brewing now on how it shapes the recovery. Can you guys maybe just give a little bit more detail on how -- I think you measure efficiencies as stages per day, but correct me if I'm wrong. How that has evolved maybe over the past few quarters as opposed to just looking at second to third quarter? And what are the primary drivers? Is it purely just the shift to zipper fracs? Or are there other things going on that maybe we don't see?

Dan, this is Jim. Let's be clear that stage count in third quarter of '18 was lower than third quarter of '17 because we were working all the time in third quarter '17. In terms of stages per day, stages per day worked, stages per day that we're on the site, it has increased. I just don't have that number right in front of me right now. I'd tell you...

Zipper fracs, this is Ben. Zipper fracs have been going up. You can typically generate a lot more stages when that's the case. But I think, to your point, there are a lot of things that we and our customers are doing to try to eke out more stages. It's better coordination with the customer, better coordination between service providers on location. We're sharing metrics with the customer, they're sharing them with us. So there's a lot that's going on, but to allude back to Jim's comments earlier, there have been -- there have been -- we don't have it quantified it right now, but there have been some nice increases in efficiencies when we're on the wellsite, and our competitors are doing the same thing. That there have been some nice strides. It will continue to improve, I believe, but at a slower pace than it has over the last, say, 12 months.

And we'll take our next question from Blake Gendron with Wolfe Research.

So I found something very interesting, one of your peers talked about consolidating horsepower. Basically taking several fleets and consolidating it to a fewer number of fleets. So playing devil's advocate on efficiency gains here. As we move from delineation to development mode and you look around the rest of the domestic frac market, is there more work to be done consolidating this horsepower? And how does that follow through to the supply-demand dynamics of the broader industry?

Blake, this is Jim. We understand that comment, and implicitly, we've done the same thing by adding equipment and having the same number of fleets. So I think the general principle you're speaking to is the fact that it takes more horsepower to get work done, not because more horsepower will do the same work more quickly. The physics don't dictate that. But because if you're on site for much longer and you need more equipment to run it at lower speeds and have back up and that type of thing. So that is one offset. If you're measuring pressure pumping capacity in terms of fleets, that certainly is an offset. And also [it could be offset price].

And we'll take our next question from Ryan Pfingst with [ERF].

Just going back to where your fleets are located now. Jim, I think you said 11 are outside the Permian currently. Were some of those mobilized due to the Permian takeaway constraints? And do you have plans to mobilize any more out of the Permian in the next few months or so?

No. It's a good question, probably deserves some clarification. We have not moved any fleets out of the Permian to other areas. We have a little -- we move things back and forth to catch jobs. But in general, about a little less than half our horsepower is in the Permian and has been for a while. We have established bases in other areas, South Texas, East Texas, the Midcontinent and up in the Bakken, and would be happy to move that equipment if there was a better short-term or medium-term job opportunity, and we do that frequently. But there's been no migration of equipment due to anticipated Permian takeaway capacity issues at this time.

Okay. And then, Jim, do you have an estimate of the industry's current marketed fleet of frac horsepower? And whether that has meaningfully changed in the last 3 months?

I do not. I could say anecdotally that it's increased by a little bit. I don't know. It's increased some over the past few months, we've talked about that in our comments. I don't know how much. Sorry, haven't done the work.

And we'll take our next question from Jud Bailey with Wells Fargo.

Most of my questions were answered. I just had one high-level question, it's been touched on, and that is just your capital allocation or capital needs for next year. And I'm thinking, could you maybe talk at a high level on areas across your portfolio where you may be creasing capital needs or decreasing? Just trying to think of where you will be allocating capital next year between coil and some of the other business lines, and how you're thinking about that on a go-forward basis.

Jud, this is Jim. We do see some opportunities in large-diameter coil tubing. And that's something we have been in for a long time, so we have some expertise there. So as we discussed, we are increasing the size of our coil tubing fleet on the large-diameter side. Pressure pumping is that big mix of -- we're going to upgrade some equipment, we're going to replace older component -- older intermittent-duty components with continuous-duty components whenever it's time to do replacement, and we will probably buy new equipment that replaces some parts of the fleet. As you know, we've got different engines now, continuous-duty components and the work is harder. So I think those are the big ones. We don't know -- currently don't know of any other real CapEx needs.

Nothing out of the ordinary. Pressure pumping will continue to command the largest amount because of its size and the capital-intensive nature of the service line. Reasonable question, but I think from a larger CapEx standpoint, it does boil down to pressure pumping and coil tubing at this point.

Okay. And then my follow-up is just a follow-up from one of the comments you guys made on frac efficiency. And improvement or increase in zipper frac-dedicated work, that's been a driver, of course. I think you also cited some technologies that you're using to help drive better efficiency. Could you elaborate or comment on things you're doing to quantify things or movement around the wellsite better, this quarter or recently, than you were maybe earlier in the year?

Well, I think you may be referring to something that I alluded to earlier around some of our data initiatives. I think it's just an opportunity to be able to operate the equipment on location more efficiently, perhaps with less employees on location, that's made it a little more easy as well because of the long-term nature of being on the wellsite, you may not need as many people to -- you don't need as many people to move equipment around and things like that. So we're looking for opportunities to be able to, again, operate the pumps with fewer personnel on site. And that -- some of that is in the systems with the pumps and things like that. That's something that we've been working on for some time. And to be honest, there's -- it hasn't yet kicked in, but we do anticipate that it will in the next few quarters. Is it enough to quantify? It's not clear at this point. Again, I think it's just one of those incremental improvements that we try to focus on, and it'll show up over time. That type of initiative, together with other things we're doing, we hope will flow through and be evident in our overall returns.

And we'll take our final question from Marc Bianchi with Cowen.

I wanted to follow up on a couple of comments you guys made around the stage count growth being up around 10%. Based on the mix of revenue, Jim, you gave, it implies frac revenue was down, I think 12%. You mentioned pricing was down a little bit. But just curious why activity would be up so much, but revenue down. You mentioned, I think, the sand prices were like 10% to 14% of that. But if you could just provide some more commentary around the mismatch there.

Yes, Marc. Honestly, it's hard to get a hold of when you consider the fact that we're paid by stage. But utilization, there was pricing. I think we were probably equipped to do many more stages than we did because of the whitespace that emerged in the calendar. It's just utilization. It's difficult to really quantify.

Well -- and you -- we earlier alluded to the regional in-basin sand that impacted -- impacts the revenues as well, so.

Yes, that's correct.

And it appears that we do have one last question in the queue from John Daniel with Simmons & Company.

Jim, I don't think you've ever answered this before, so I'm going to try real quick. Can you tell us how many frac pumps you guys rebuilt or overhauled in 2018? And how that might change in 2019? That's all I've got.

John, I don't have that number in front of me. We are -- in 2019, I can tell you that there will be, let's just say, between 10 and 15 pumps that are going to get -- that are already pretty good and have 3 axles on them, and they're going to get new transmissions. That is a small number. That's not a full answer to your question. So I don't have that in front of me for [2018].

I'm just trying to get a sense if the aftermarket activity, if you will, is accelerating into '19. That's another narrative that people believe will happen. I'm just curious if that's actually showing up in your data.

You can't ask too many questions about pressure pumping. I just don't know the answer to that one.

I think it kind of gets back, John. I mean, I think it's a reasonable question. I think we're still planning at this point in terms of the timing and the magnitude of whether it be upgrading, of refreshing, whatever, our fleet. So we're still working through that. Reasonable question, but we don't have the answers to that right now. This is kind of our planning season, and some of those decisions are kind of underway right now.

And there are no further questions. At this time, I would like to turn the conference back to Jim Landers for any closing remarks.

Okay, Riley, thank you. One closing remark. Rick, Ben and I were just notified not too long ago that our webcast was disconnected for about 10 minutes. So we apologize for that. It was a technological error that we didn't know what's happening. The replay on the web, on our website will contain the entire call, and then the transcript that you'll see through the various stages sources you have will have everything on it, including our prepared remarks and the Q&A. So just want to note that.

And with that, we appreciate everybody who called in for your interest in RPC. And we will see you all again soon. Take care.

And this concludes today's call. As a reminder, the replay for this call will be available on www.rpc.net. We want to thank you for your participation, and you may now disconnect.