Jim Landers – Vice President of Corporate Finance Rick Hubbell – President and Chief Executive Officer Ben Palmer – Chief Financial Officer.

Jim Wicklund – Credit Suisse Chase Mulvehill – Wolfe Research Marc Bianchi – Cowen and Company Praveen Narra – Raymond James Brad Handler – Jefferies Michael LaMotte – Guggenheim John Daniel – Simmons & Company Waqar Syed – Goldman Sachs Rob MacKenzie – IBERIA Capital David Anderson – Barclays Kenneth Sill – SunTrust Robinson Humphrey Thomas Curran – FBR Jud Bailey – Wells Fargo.

Good morning and thank you for joining us for RPC, Inc.’s Third Quarter 2017 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. At this time, all participants are in a listen-only mode.

Following the presentation, we will conduct a question-and-answer session. Instructions will be provided at that time for you to queue up for questions. I would like to advise everyone that this conference call is being recorded. Jim will get us started by reading the forward-looking disclaimer..

Thank you and good morning. 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 2016 10-K and other public filings that outline those risks, all of which can be found on RPC’s website at www.rpc.net. Also 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’re also required to use EBITDA to report compliance with financial covenants under our revolving credit facility.

Our press release today in our website provides a reconciliation of EBITDA to net income, 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 for any reason, please visit our website at www.rpc.net for a copy.

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

Thanks, Jim. This morning, we issued our earnings press release for RPC’s third quarter of 2017. The U.S. domestic count increased again during the third quarter of 2017, though at a much lower rate than in the previous four quarters.

RPC’s revenue increased by 18% sequentially, a rate greater than the rig count because of our customer’s continued high demand for oilfield service providers, capable of operating in highly service intensive environments.

Based on our improved results and strong balance sheet, our Board of Directors has declared a regular quarterly cash dividend of $0.07 per share and an additional $0.07 per share special year-end dividend. In addition, we repurchased almost 727,000 shares of RPC’s common stock on the open market during the third quarter.

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 increased to $471 million, compared to $175.9 in the prior year. Revenues increased compared to the prior year due to higher activity levels and pricing for our services, higher service intensity and activation of our previously idled revenue-producing equipment.

EBITDA for the third quarter was $137.5 million, compared to a loss of $4.4 million for the same period last year. Operating profit for the third quarter was $97.4 million, compared to an operating loss of $56.4 million during the same period in the prior year.

Cost of revenues during the third quarter was $294.8 million, or 62.6% of revenues, compared to $146.6 million, or 83.4% during the same period last year. Cost of revenues increased due to higher activity levels and service intensity.

As a percentage of revenues, cost of revenues decreased due to improved pricing for our services, as well as leverage of higher revenues over direct employment costs. Selling, general and administrative expenses were $39.7 million in the third quarter, compared to $34.9 million in the same period last year.

These expenses increased due to higher compensation costs, primarily incentive compensation as well as other expenses consistent with higher activity levels. As a percentage of revenues, these costs decreased to 8.4%, compared to 19.8% in the same period last year, due to the leverage of higher revenues over fixed expenses.

Depreciation and amortization were $39.6 million during the third quarter of 2017, a decrease of 23.8%, compared to $52 million for the same period last year. Net gain on disposition of assets was $503,000 million in the third quarter, compared to $1.1 million in the same period last year.

Our Technical Services segment revenues for the quarter increased to 179%, compared to the third quarter of the prior year due to improved pricing and higher activity levels. Operating profit was $104.3 million, compared to an operating loss of $48.6 million last year.

Our Support Services segment revenues for the quarter increased by 21.7%, while the operating loss decreased 62.8%, compared to the same period last year due principally to improved activity levels and pricing in the rental tool service line, which is the largest service line within this segment. Now discuss our sequential results for a moment.

On a sequential basis, RPC’s third quarter revenues increased 18.1% to $471 million from $398.8 million in the prior quarter. Revenues increased due to higher activity levels and improved pricing for our services as well as activation of idled revenue-producing equipment.

Cost of revenues increased by $40.8 million or 16.1% due to higher materials and supplies expenses and employment costs, which resulted from higher activity levels and service intensity.

As a percentage of revenues, cost of revenues decreased from 63.7% in the prior quarter to 62.6% due to pricing improvements and operational leverage from higher activity levels. Selling, general and administrative expenses during the third quarter of 2017 increased by only 1.4% compared to the prior quarter.

However, as a percentage of revenues, SG&A expenses decreased from 10.1% in the prior quarter to 8.4% due to leverage of higher revenues over relatively fixed expenses. RPC’s operating profit during the third quarter of 2017 was $97.4 million, compared to $67 million in the prior quarter, an increase of 45.3%.

RPC’s gain on sale decreased from $3.8 million in the second quarter to about $500,000 in the third quarter. As we mentioned last quarter, we recorded a $3.5 million gain on sale of operating equipment related to our oilfield pipe inspection service line during the second quarter.

Net income increased by 30.8% during the quarter from $43.8 million or $0.20 diluted earnings per share to $57.3 million or $0.26 diluted earnings per share in the third quarter. The current quarter include the tax adjustments that negatively impacted diluted earnings per share of approximately $0.02.

RPC’s sequential EBITDA increased from $110.3 million in the second quarter to $137.5 million in the third quarter, and the EBITDA margin improved from 27.7% to 29.2%. Our Technical Services segment generated revenues of $455.7 million, which was 18.2%higher than revenues of $385.5 million in the prior quarter.

Operating profit improved to $104.3 million, compared to $70.9 million in the prior quarter. Our operating margin in this segment increased from 18.4% to 22.9% in the current quarter. Our Support Services segment generated revenues of $15.3 million, which is 14.5% higher than revenues of $13.3 million in the prior quarter.

Operating loss decreased to $2.1 million, compared to $3.3 million in the prior quarter. As of the end of the third quarter, RPC’s pressure pumping fleet remained unchanged at $925,000 hydraulic horsepower, of which approximately 95% is manned and available to work; and this compares to 80% at the end of the prior quarter.

Our total head count increased 7.6% during the third quarter. Also the third quarter 2017 capital expenditures were $44.4 million. We expect full year 2017 capital expenditures to be approximately $150 million, a portion which will be directed towards the purchase of 127,000 hydraulic horsepower with delivery expected during the first half of 2018.

During the first nine months of 2017, we repurchased a total of approximately 1,075,000 shares of RPC’s common stock on the open market. And as of the end of the third quarter, our cash balance was $136.9 million with no outstanding debt. With that, I’ll now turn it back over to Rick for some closing remarks..

Thanks, Ben. During the third quarter, we began to experience increased labor cost and raw material inflation, but have managed these cost increases in order to minimize their impact on our profitability. As previously discussed, we have ordered additional pressure pumping equipment and activated substantially all of our idled equipment.

We are very pleased with the current operating environment and prospects. Although the increase in the drilling rig count has moderated, we have indications of strong customer activities for the remainder of 2017 and into 2018. Thank you for joining us for RPC’s conference call this morning. At this time, we will open up the lines for your questions..

Thank you. [Operator Instructions] We’ll take our first question from Jim Wicklund with Credit Suisse. Please go ahead..

Jim?.

Jim, sorry, we cannot hear you, if you can….

We can only barely hear you..

Yes..

Is that better? How about that?.

Yes, much better..

Yes..

[Indiscernible].

Okay..

You say you’re booked through the remainder of 2017, which is good, and in the 2018, which is the positive part, and of course, oil prices look to be up in 2018, but nobody knows if these E&P guys are going to outspend cash flow.

How far in the 2018 do you have visibility right now? And do you think that the pricing, I realize it won’t be at the same momentum of the first half of this year.

But do you think that, that pricing will continue up? And I ask that because the industries – investors are concerned that if margins get high enough, everybody will start ordering new equipment. Obviously, you get the best margins in the business. So you can afford to do so.

But I’m just curious to know how far into 2018 you have visibility and what you think of pricing through 2018?.

Jim, this is Ben. We continue to be on the spot market, but we do have ongoing discussions with all of our good E&P customers, and we are talking actively about drilling plans deep into 2018. But we know there’s no contracts or firm commitments, but there’s certainly much, much discussion about their need for and desire for services from us.

So we look at that as obviously very good, and we are talking a lot about long-term plans. So whether that’s – how deep is that into 2018, you know it varies. But we all know that, that can change if the customer puts off their plans or whatever. As you talked about if their funding drives up, we know that can change.

So we’re not counting on it, but we’re planning for it and anticipating it.

And we think with that backdrop and given some of the dynamics with pricing that we’re seeing from other pressure pumpers in the market, you know some people are doing well, some people are not doing so well, I hope and expect with increased service intensity and activity and some of the struggles of some of – some competitors out there that – maybe there can be some positive momentum with pricing.

That’s what we’re hopeful of. We – as you said, we have good margins. We have good returns, but we would love forward to be even higher. Our team is executing very well, and we’re in a good environment and some good businesses in the right spots. And as I said, the teams are executing well. So it’s reflected in the numbers..

It’s a good time to be in the spot market. And good, I’m not sure, is really a good enough adjective for how well your margins run. On the sand and logistic side, companies have reported obviously. And efficiencies, E&P companies have talked about green crews. Last mile logistics was blamed recently on one.

Can you tell us how you guys are doing on the sand and logistic side? You own your own sand, so that keeps you vertically integrated.

But can you educate us a little bit on what’s going on in the logistics business of sand today?.

Jim, this is Jim Landers. As you pointed out, we do have a sand mine. It provides a minimal amount of total sand that we use, but it’s nice to have when it’s there. Certainly, we’ll echo the comments that trucking has gotten more expensive, and it’s been more difficult, but it’s a process we’ve managed fairly well.

Our demurrage expense in third quarter was minimal, slightly higher than second quarter but still not enough to move the financial results. So it’s just a process we have to manage, and it has not impacted us – did not impact us in third quarter in a negative way. Again, just something we have to manage..

I can – I’ll add….

Congratulations, guys..

Thanks, Jim..

Go ahead, I’m sorry..

I was going to say that we did see a little bit of increase in sand prices. But I would say, being on the spot market and our relationships with our customers, we’ve been able to pass most of our cost increases onto our customers. And that too is reflected in the numbers and in the margins..

Okay, thanks guys. Great quarter, thanks..

Jim, thank you..

Thanks, Jim..

We’ll go to our next question from Chase Mulvehill of Wolfe Research. Please go ahead..

Hey, good morning..

Hey, Chase..

Hey. So real quickly, I just wanted to ask about efficiencies across your pressure pumping fleet.

So if maybe you could just add some comments there and maybe talk to the skew or the variability between the efficiencies across your feet? And then what’s you’re doing to kind of narrow the variability of the skew across your fleet?.

Chase, this is Jim. I’ll try to respond to that one. We are doing more zipper frac work now than we were. And as everyone on this call knows, that allows you to stay on site longer. And in some of the Permian Basin jobs, you’re on site for very long time because you’re doing those different zones. So you’re there for a long time. That helps efficiency.

It also allows you to make a 24-hour a day job really 24 hours a day and many successive days going onto the jobs. So that has helped us. You’re talking about skew. You know we still do some vertical work. We haven’t abandoned that at all. Those jobs are shorter, and they’re small in terms of revenue, but they’re very profitable.

So while you might look at that and say that’s not overly efficient, we would say that it’s profitable for us and work that we like. The Permian is probably the most efficient place to work just because of all the logistics in place and how all those things are going.

And I think that’s probably the only real comments we have about variability and efficiency across our different….

I might add maybe a little more color. This is Ben. That’s clearly one of the things that we do focus on. Again, execution wise, our guys are doing a great job trying to keep the utilization as high as it can be.

I think one of the – another benefit of being on the spot market is if you have delays of a particular customer and you’re "booked out" with the customer and they call and say, oops, I need to slip things. That job we had scheduled a couple of weeks from now, we need to let it slip.

If you’re committed to that customer, you’re sort of in a tight spot and you can’t reschedule that. But our processes are such an approach to managing our customer relationships are we can try to be nimble and try to redirect our crews onto another job. And so that helps.

All things being equal, that helps fill up the calendar and keep us more efficient than we would otherwise be..

Okay.

And then zipper fracs, what percentage of your fleet was – or stages we’re doing zipper fracs in 3Q? And how does that compare to 2Q?.

47% zipper fracs by stage in 3Q, and that’s up from the low 40%s in the second quarter..

Okay.

And what do you think you can – what’s kind of peak max that you can get on the zipper frac penetration you think?.

Don’t know. [Indiscernible] More is better..

Yes.

So do you think you’re at peak efficiency? Or do you think that you’ve got opportunity to continue to push efficiencies across your fleet?.

Chase, there are always places we could get better. And it’s a huge group of service providers on a location trying to get a completion job done. You know things always come up. They’ve been minimal. But you could always eliminate efficiencies and get a little better. I don’t know get around that..

Part of what we’ve had to balance, and again, team’s done a great job doing this. As we rolled out the idle equipment, that’s not – that’s very difficult to be perfect. So we’ve been rolling that out. The utilization has stayed great.

But now that most of the equipment has now been deployed by the end of the third quarter, we would expect all things equal that it’ll be a little more steady. We will then staff and staff with less green employees and that in and of itself should help create at least some incremental efficiency..

Okay. You’ve done a great job there, especially compared to your peers on the margin side. So last one, a quick and easy one.

So when we think about sand inflation or deflation, do you prefer sand inflation or deflation and why?.

Makes me think about the gasoline business or something..

Yes. We don’t give away trade secrets either. I don’t know..

Okay. I’ll leave at there. I realize it probably what it go there. So all right, Ben, Jim, thanks [indiscernible].

Yes, thanks to you..

Next question comes from Marc Bianchi with Cowen and Company..

Thank you.

Maybe just first, Jim, could you provide the revenue breakdown by business line?.

Yes. Absolutely, Marc. Happy to. So the numbers I’m about to give you are the percentages of consolidated revenue that our top five service lines comprise for the third quarter. Pressure pumping is our largest service line and was 64.5% of revenues. Thru Tubing Solutions is our second biggest service line, and that was 17.3% of revenues.

Coiled tubing is our third largest, and it was 6.9% of revenues. We have a nitrogen service line, which accounted for 2.6% of revenues during the third quarter. And then, rental tools in our Support Services business is – was 1.8% of revenues for the third quarter..

Okay, great. Thanks. So with that it looks like the pressure pumping business grew about 20% here in the third quarter.

Can you tell us how much of that was activity versus price?.

Yes. We’re – I guess just basically, we would say that it was about 1/3 of it was activity and 2/3 was price..

Okay, great. And as you think about the pricing more near-term, Jim was asking earlier about longer-term in 2018. But if you think about where you are right now being a spot player, perhaps you’re at the front end of the pricing uplift and perhaps now things are maybe stabilizing. Curious to hear your comments on the near term.

And then also as it relates to some of the cost inflation you’re seeing, if you’re getting price, are you getting it just to cover cost? Or is it a little bit in excess of cost or a little bit below cost? Please give us some color there, if you could..

Well, I alluded to it a little bit earlier. I think at this point, heading into the holidays and uncertainty about how busy everybody will be, it’s time for celebration and whether we’ll push pricing as much during the holidays or not, we’ll yet to be seen. But I think – with the results, I think a lot of it depends on job mix.

But again, our relationships with our customers, we’re saying, this is our pricing, this is our required margins, this is our required returns that we’re looking to get. So if we have price increases, we need to talk about modifying our pricing. And so that’s working for us. Again, and that’s reflective in the numbers.

So as I alluded to earlier, we hope with some of the dynamics and what we’re hearing and hopefully competitors and across the board everybody will be looking to try to get their returns – margins and returns to a more acceptable level. So we think that will provide some impetus or backdrop to foundation for pricing to improve.

And there’s indications, maybe with the price of oil firming a bit that all those things may set us up. And increasing service intensity, which is going to absorb more and more frac capacity that we hope all those things are a backdrop for continued increases in industry-wide pricing, which we’ll be able to benefit from as well..

Sure, okay. And as you look to the fourth quarter, with what you can see right now with holiday plans and where you are in the pace of reactivation, sounds like everything that could be deployed is deployed and none of the new equipment’s going to really hit in the fourth quarter.

Fair to think about the activity portion of your revenue and pressure pumping being pretty flat?.

Well, we’ll, on average, have more equipment deployed..

That’s true. Yes..

Okay.

So some benefit from a little bit higher exit rate?.

Yes..

Okay, well, thanks. I’ll turn it back..

Thanks, Marc..

Thanks..

We’ll take our next question from Praveen Narra with Raymond James..

Hey, good morning, guys..

Hey, Praveen..

I guess just thinking about kind of the fleet deployment additions in the quarter, were those still kind of back-half related as we talked about before? And so – sorry..

I’m sorry. We indicated by the end of the third quarter, we’re about 95%. So there were just a few pumps that had not yet been deployed. But the average for the quarter is somewhere in the mid-80s..

Okay, perfect. And then I guess you talked about – to Jim’s question, you talked about kind of longer-term plans and talking to some customers well into 2018.

Is the hesitancy to lock in any portion on contracts, is that on the all centers or is that with the customers as well in terms of the longer-term contract?.

I would say that certainly customers bring up a lot. They would love to lock in. Pricing at a lower level promising certain amounts of activity levels and things like that. In our experience that often times does not work, right? So we like the spot market.

It’s not to say that at some point we wouldn’t be able to establish some terms with the customer that we had a good relationship with, and we might enter something that looks more like a contract. But we like where we are now. And there’s always that the balancing act. It is a relationship that we have with our customers.

So we’re not trying to push it to the very, very end. We’re trying to be efficient together, look for ways to that if they have to push the job, again that we’re all working together to get – keep us busy, keep their needs for services met. And right now – again, we have those good relationships, and we want to maintain those..

Right.

And then I guess, in terms of the Technical Services business, is it fair to think that the pressure pumping margins are accretive to that on an EBITDA basis?.

Meaning higher revenues accretive to EBITDA? Yes, sure..

Yes..

Okay.

And then do you have by chance a ballpark of the revenues for pressure pumping that we derive from sand?.

No..

No, okay. Thank you very much, guys..

Okay, Praveen. Thank you..

We’ll take our next question from Brad Handler with Jefferies..

Yes. Thanks. Good morning..

Hey, Brad..

I didn’t see the word Harvey mentioned in your press release, which, I guess, I respect. But can you quantify for us, did Harvey have an impact on your operations? I think it had a small impact on your revenues in the quarter..

Brad, it was minimal. You know we have a tubular services business with few locations, one in Houston. I think that was shut down for a few days. We had some sort of indirect impact from letting employees, who were maybe in West Texas go home to South Texas and check on their homes and their families.

We’re doing some things to help some employees who had damage to their homes. We’re doing that internally. But there was not enough revenue impact to notice. It’s been talked about a lot. There were some shortages of assets and some temporary supply disruptions there, but really didn’t impact us enough to call out in a negative way..

We don’t have any offshore work..

Yes..

And so really no noticeable impact..

Okay, okay. Fair enough. And then maybe just one unrelated one from me. And I guess Chase was maybe sort of getting at it with his question.

But I’m curious, as you’re talking with your customers around 2018, I am curious if West Texas sand availability is coming up in the conversation? And if you’re getting the sense that as a result of that, perhaps, customers are considering using more sand and are changing well designs around that availability at all? It’s obviously a very leading question, but I guess I’m curious whatever context you can give around West Texas sand having an impact in your conversations around the future?.

Brad, our sense from recent field visits and discussions with our operations guys as recently as last night, West Texas sand is so much of a wildcard and someway it’s sort of a binary outcome that we don’t know of anybody making plans or changing their operational or their job designs based on the potential increased availability of West Texas sand.

So we just don’t have any information on that one..

Too early to tell..

Yes, too early to tell..

Okay, very good. Okay, thanks for that. I’ll turn it back..

Thanks, Brad..

We’ll take our next question from Michael LaMotte with Guggenheim..

Thanks. Good morning, guys..

Hey, Mike..

I wanted to follow-up on the comment of the growing intensity absorbing more capacity.

Is that happening in your fleets as well? Are you seeing average fleet size increasing?.

We are, Michael, given the operational reality that when you’re on site for a long time and running equipment that historically has been intermittent to the used equipment when you’re running at 24 hours a day for multiple days, without a break, you need more equipment in some sense for redundancy but also to have all the equipment that’s there running, running at lower speeds.

So that dynamic is a catalyst for larger fleet sizes. That’s correct..

I’d also add to that, that we had for some time – this is Ben, for several months now or longer, been making revisions to some of our equipment design and so forth to handle the new reality of wells with higher service intensity.

And that too would be reflected of the equipment that we talked about that we ordered that has components on it that are right out of the gate, more suited to the new type of activity that we’re participating in.

So yes, it’s been like the fluid ends that we all had to deal with a number of years ago, we’re doing the same thing with other components and top designs and things like that.

So we’re responding to the changes in the trends, and we hope we’re ahead of that or at least keeping up with those changing trends to be able to respond to the opportunities that the new well designs and frac approaches present to us..

Okay. Thank you, Ben. And if I could ask a question on capital allocation, this year, you’re sort of on the run rate, I guess, to do about $450 million in EBITDA. You mentioned $150 million in CapEx. And if my math is right, you’ll end up with dividends and repurchases returning about $65 million in cash.

If margins were to stay roughly the same throughout 2018, what do you think the mix of CapEx to cash return would look like?.

CapEx will be higher because we’re buying equipment..

Yes..

So that part of the answer is easy. We also – as most people know are very dedicated to being responsible stewards of cash and rewarding our shareholders as much as possible. So I think you can look for healthy dividends and, when appropriate, share repurchases.

So it’s kind of the same three legs of the tool as always, just higher CapEx, and being responsible to balance sheet. Unless something just extraordinarily good happens, we don’t plan to go into debt..

I’m not saying I’m going to add to it, but I think that, too, did – I think it’s healthy to forecast out some of those things, think about what the possibilities are. But those decisions about both CapEx and cash returned to shareholders are decisions that are made not much in advance.

They are made periodically based on our view, prospects, alternatives, what alternatives are available to us and which do we think are best at the time. So we’re not making decisions today about what our returns to shareholders are going to be six months or nine months from now..

Maybe another way to ask the question is that there is no need to stockpile cash on the balance sheet, right? Really, excess cash gets return?.

Yes. That’s fair to say..

Yes. We want to be cash efficient. That’s right..

Okay, great. Thanks, guys..

Sure, thanks..

We’ll go next to John Daniel of Simmons & Company..

Hey guys, thank you.

Jim, I guess, first question for me is, when you look at the new horsepower additions, how much of the decision to make those was driven by the healthy returns on that spend versus just the desire to get ahead of the Tier 4 transition and get equipment locked out now?.

Healthy returns prospects for the future and our decision or our belief that people are going to continue to need pressure pumping, the fact that there is high wear-and-tear on the equipment, all of those – I haven’t spoken of Flinstones yet, all of those are things that were important.

Getting ahead of the Tier 4 requirements cuts the cost of that equipment by about 10% and enhances sort of all of the above. So it’s a factor but not a key deciding factor. In other words, it goes without saying that if the market were not good or we didn’t feel good about our ability to execute, we wouldn’t buy equipment just because it was cheaper..

Okay.

Are you running any Tier 4 equipment now?.

I believe we do very, very little..

Yes. We had a couple of customers in the Northeast who are interested in Tier 4 equipment a couple of years ago, but I don’t know if any of them were running..

Okay. Fair enough. The 2018 CapEx spend, I know you probably haven’t finished your budget. But given the expansionary CapEx sort of provide a range, I would assume your maintenance CapEx is going to be up a lot just given how high the utilization is, too..

Yes. I think that’s a fair statement, and yes, it’s too early to really give much of a range. Jim alluded to earlier. I think it will be – my guess would be it’s reasonable to assume that’s going to be higher than it was here and what we’re projecting for 2017, but too early to tell.

Again, we’re looking at opportunities and reevaluating our various fleets of equipment. And so that’s going on right now..

All right.

Are there any other expansionary CapEx efforts, coiled tubing, anything else that’s noteworthy? Or is it primarily just focused on frac?.

At this point, just pressure pumping, John. We’re always looking to things as you know, but at this point, pressure pumping..

And no firm orders to be announced at this point..

Okay. And then I guess the last one for me. And this was – the answer is probably no, but I’ll just ask anyway.

Have you guys lost any work with any incumbent customers due to a competitor offering a lower price?.

Oh, gosh. It sure happens all the time..

Yes..

So there is – okay..

When you say a lot of customers, it may have been we lost or we didn’t get a particular job. We’ll come back around at the competitor who does a bad job or the competitor comes back. So we’ll now on our price, the customers may come back to us. So certainly, we have not won all jobs we’ve been on..

Yes, absolutely. Plenty of opportunity costs in the sense that if we weren’t booked out, there would be real opportunity costs. But since we’re booked out in the future, there’s no point in being price competitive at this point..

Okay, okay. That’s all I’ve got. Thank you very much..

John, thanks..

Thanks..

We’ll go next to Waqar Syed with Goldman Sachs..

Thank you.

In terms of the CapEx for the new builds, how much is going to be incurred this year and how much in 2018?.

We already have it. It’s 2018..

Yes. It’s about 1/3 this year and 2/3 next year. We’ll have to make a few prepayments. Obviously, the total will be upon delivery. And the way we have it scheduled out, we may get some pumps very, very, very late in 2016, but they won’t contribute much to revenue.

But that would drive the CapEx, right? We’ll take delivery late in the fourth quarter and drive the CapEx but not the availability of equipment to work..

Okay.

And then the total CapEx for the new build is roughly, what, $100 million to $120 million, something in that range?.

That’s right..

Yes..

Okay. And then a question on zipper fracs was asked earlier, I believe, by Chase. But just wanted some clarification.

If you just look at the horizontal jobs that you have done, what percentage of those were zipper fracs versus the traditional systems?.

Waqar, you’re asking what percentage of horizontal work was zipper work?.

That’s correct, yes..

Let me work on that. I’ll answer it by the end of the call or try to..

Expect already from the horizontals..

Yes..

And then – and could you also tell us how many crews on average were working in the quarter? And then what was the exit rate for the third quarter?.

Crews are very difficult. There are different kinds and sizes and types depending upon the type of work. But as we’ve added the equipment, we exited the, I think, the third quarter with around 20 fleets the way we talk about them. Crews were a bit lower. So we’re doing a lot of 24-hour work. So….

Okay, 20 fleets..

Waqar, approximately 50% of our horizontal work was zipper frac..

Okay, great. Thank you. That’s very helpful..

Thanks, Waqar..

We’ll take our next question from Rob MacKenzie with IBERIA Capital..

Thanks. Good morning, guys..

Hey Rob, good morning..

I wanted to come back to the sand question from a little bit different angle if I may.

How much do you guys think sand volumes being pumped per well of late have been driven by availability in the supply of sand versus desired optimal design for the job? i.e., has the lack of available [indiscernible] constrained amount of sand being pumped? And as such, as Permian sand comes online, do you expect to see volumes increase again?.

We don’t think availability of sand has been an issue. I guess I’m kind of answering it the opposite way. We know that because – we know that our customers like using more sand. And so I don’t know. I don’t think it’s been a factor. I think they’ve had everything available that they wanted available, so….

I think, for the most part, I think that will show up in pricing, right? If pricing was increasing much more than low to mid-single digits. I think that would indicate that there was a shortage. But given that there’s not significant inflation of sand prices, I don’t think that’s impacting designs that much at this point..

Right..

Okay, thanks. And then shifting gears, I guess, to overall pricing from frac services.

And again, in a market that everyone acknowledges is still a little bit undersupplied with deflationary pressures creeping in and many of your competitors still at subpar profitability, how do you interpret the outlook there for further price increases despite their moderating this quarter scores? Do you have more room for price expansion as we go into 2018?.

Rob, we believe so simply because the work is harder on the equipment. If the equipment is wearing out, that’s causing more maintenance or more maintenance capital expenditures, wherever you want to put on the geography or the financial statements. Customers continue to demand what we’re doing. So – and this is a hope as much as a prediction.

But we hope that everybody continues to go to their customers and says, I need to earn a reasonable return for the work I’m doing for you, important work. And the work is getting harder, so I just need better pricing.

And there will be pushback, but eventually, the free market will either make that happen or drilling and completion will really slow down in this country. In which case, both price of oil will go up and it will happen later..

So I know and I guess, from a pricing perspective, there’s – certainly, if we’re going to maintain our returns, if the work gets harder and M&R costs are higher, pricing has to go up to full returns and margins to have the opportunity to stay the same. So whether we get net pricing improvements, we’re hopeful of that.

Again, we hope that the industry – the frac industry will, in total, will look to say we need to get our returns up and that there’ll be some – there’ll be a little more consistent pushing for those acceptable returns because we know that it can’t go on forever.

We know that we’ve seen it very recently what can happen if you don’t get special returns. Just the equipment is going to burn up and people will have very severe financial difficulties.

Luckily, we’re positioned with – we’re positioned in our position with the quality of our equipment and where we are with our customers and able to provide the quality services. We’re not experiencing those same situations, but we’re hoping more of our competitors will push pricing..

Okay. Thanks. And then I guess my final question here stems towards perhaps some conversations you’re having with your customers.

What can you share with us in terms of, a, how they think about spending going into next year in terms of the recent growth and pressure around spend and cash flow? And as part of that, do you have any visibility into their choice as to whether to complete docks or the new drill wells? How do you see that, that dynamic playing out?.

As recently as last night, we asked some our sales and operations people and don’t have any insight there. Obviously, the question about living within your means and capital discipline is a huge topic in the analyst community or in Wall Street right now with regulatory E&Ps.

And we’re aware of many of those conversations, but we haven’t seen an operational impact or forecasting impact yet..

Okay. Thanks, guys. I’ll turn it back..

Rob, thank you..

We’ll go next to David Anderson with Barclays..

Hi, good morning. I was just wondering about kind of your approach on the spot market versus kind of a lot of your customers on the dedicated fleets. I know you’ve touched on this a few times. But we’ve noted that not only you seem to be getting better pricing but also better margins.

So just kind of curious, how do you think about that? Is that because you have a different book of customers? Is it your ability to be more efficient? You also touched on the ability of being more nimble. So it sounds like you can avoid some of these pitfalls of customers who switch around.

So could you just kind of talk about that a little bit of why you think it’s different?.

David, this is Jim Landers. In general, a general comment, if the spot market pricing is a bit higher than contract pricing. And as we’ve discussed during the quarter and at your conference, our customer base pretty much mirrors the U.S. drilling rig count right now.

We have probably a little more predominance in the private E&Ps but – so we think we have good customer relationships. But beyond that, there’s nothing particularly unique about our customer base.

One thing about contracts is that you may enter into a contract with good faith and be ready to go, but your customer, for reasons beyond his or her control, is not able to do the work that they said they were going to be doing. And nobody regrets it more than them, but we regret it the second most, and we just don’t like being in that position.

So as Ben said earlier, we’re in a position now where we’re in the spot market, but that’s not a daily transaction market. That’s a series of job or a couple of pads that might extend for two months or a month, something like that.

And those jobs when you have people waiting for you, if those get pushed for some reason, you can replace them more easily. So that’s the position we’re in, and being nimble is a key driver to success, being able to replace people or work with people if things slip. So that’s just where find ourselves right now.

We – as Ben said, we love a great contract with the right price. You have to be really choosy about your customer and try to understand their operations and see if they’re going to be able to do all the work that they want to do and plan to do as well. Kind of the best answer we have right now..

Well, it’s a great answer. Yes..

I’ll add to that, and this is Ben. I would just add further. I think I’ve alluded to the – that our operational guys have done a terrific job getting a good handle and understanding of the cost of doing jobs and the impact that job delays can cause and setting the right standards and consistently applying across our services.

We understand the costs and we plan accordingly and measure ourselves, and that just shows up. Again, in the numbers, it’s much easier said than done.

But it’s something that we’ve worked on for a long, long time and even more intensely in the downturn to be able to have a better handle on our costs and our cost assumptions when it comes to bidding jobs. And again, that’s showing through in the numbers and in the margins and in the returns. And it’s just where we always try to focus on..

Now this kind of spot versus kind of dedicated fleet strategy, is this the same strategy that you employed the last cycle? I don’t know, I guess, I’ve been thinking kind of 2010, 2011 or something like that when that cycle is starting to pick up.

Did you do the same thing? Or you’re still kind of primarily spot at the time?.

No. It was different. At that point, if you start – go back to 2010, we had a huge presence in the natural gas shale play like the Haynesville and the Fayetteville. And the nature of that work and the nature of the customer plans was very different. So we had, between 2010 and 2013, had a material percentage of our pressure pumping fleet on contract.

So it was appropriate for us, and we’re glad we did it. It allowed us to plan our operations and also figure out what it’s like to have a pressure pumping fleet work in a high-service-intensity environment. So that was positive for us then. Maybe positive again. But at this particular point, we’ve chosen another path..

Understood. And finally for me. Earlier, when you had announced you’re adding 100,000 horsepower, you talked about half of that’s going to replace equipment.

Based upon what you’re seeing today, and I know it’s early for 2018, but based upon the activity levels you see and utilization of your – your projected utilization of your equipment, do you have a sense as to how much horsepower you think you need to replace for next year? I mean, if you’re replacing 50 – 50 going today, you’re obviously thinking about this going to next year.

So can you give us a sense as to kind of what you think that replacement horsepower might look like?.

We actually don’t characterize it as replacing. We’ve got some lower-horsepower pumps that are going to go work in our vertical fleets where the horsepower plants are smaller. We’re also going to repurpose some of the older equipment to a pump-down service line, which is important as well. We don’t have a sense right now.

The business is dynamic at this point. Job designs change. The optimal amount of equipment that you have on site may change. So we just don’t have great numbers to offer you right now as to the number of fleets we’ll have and that sort of thing..

Okay. Thanks, Jim. Appreciate it..

Thanks..

We’ll go next to Kenneth Sill from SunTrust Robinson Humphrey..

Yes, good morning guys. First question, Just kind of following up on that one. The software is out, but you don’t ever actually see equipment retired per se because you can replace the different pieces on a trailer. So I guess, is there – you’re adding 127,000 horsepower in your equipment.

That’s all incremental to what you’ve got right now, right? There are no plans to reduce existing horsepower through attrition..

Not to any – this is Ben. Not to any significant degree. There may be a decision that a few pumps here and there that we don’t think we can push down in the line of pumps that are capable of working on more intense jobs when they push it down and some of them may fall out of the fleet. As Jim said, maybe repurposed to other service lines.

But at this point, we don’t anticipate that there will be a significant drop in the amount of equipment that we have today by the time we get to the end of next year. We think the 127,000 we’ve talked about will pretty much – you can count on that as being an incremental add to our capacity for pressure pumping..

Okay. So appreciate that, thanks. And that just kind seems like how it works. But listening to what you guys are talking about, it wears out faster. Your maintenance CapEx is going to be higher. How much faster is the equipment wearing out now versus two or three years ago? And I don’t think you talked about it.

It seems to me that it’s based on more run hours than sand volumes.

But are sand volumes a better indicator of the equipment wearing out? Or is it run time?.

Ken, this is Jim. It’s a good question but a complicated question. There are a lot of puts and takes to the answer. The general answer is that equipment is wearing out now than it did two or three years ago, unquestionably.

Some of the offsets to that comment are that fluid ends are lasting longer, and we’re replacing – when we replaced all the components, we replaced them where anybody can with continuous duty components that are more suited to longer run times.

We also would agree with you that thinking about life of equipment is more run time and hours versus volume of sand that goes through the fluid ends. So to summarize, equipment is definitely wearing out faster. There are some puts and takes, and it’s hard to put a percentage on that..

Appreciate that. The equipment is kind of gradually changing. One final question. I mean, you guys have industry-leading returns. It seems to me it makes sense if you guys deploy more capital to adding capacity. We’ve got other guys that are reporting that really still aren’t making money yet. I mean, M&A is something you guys don’t talk about.

But does it make sense in your mind to ever try to consolidate some of these things? I mean, I think consolidating some of these weaker guys with the bigger guys would make sense.

But a, is that something you’ll look at? And b, how much do you think scale matters to the logistic side of the business right now?.

Ken, this is Jim again. Scale matters but we think only within basin because of logistical advantages that you have if you’re larger in a basin. And you know our answer to that, to M&A and consolidation, which is that many times you’re – when you’re buying one out and suspect equipment, cultures don’t always blend.

So the premium above book value that you’re – that you might be paying wouldn’t be justified financially. So we always look that if you notice and you’ve been in the industry for a long time as well as an analyst, if you noticed, pressure pumping companies only consolidate when they are forced to. So I think most people will probably agree with this..

I think buying is kind of one of those conundrums to buy a struggling pressure pump or for whatever reason. Either because they had deferred maintenance, they haven’t spent extra to bring their equipment up to standard or whatever, that’s not something that we typically are interested in.

If we said, well, let’s go buy a high-quality pressure pumper, then you get into what multiple is and what the returns are, and we just typically – you can just take a lot of the guesswork out when you grow organically.

And the returns, historically for us, you can see are higher when it comes to should we be adding capacity, even growing faster organically. We look at this over the long term. We know there’s the potential that the market could become oversupplied. Our returns are quite good, as everybody has pointed out.

But the decision to add equipment is not necessary – is not dependent solely on how we did the last quarter or the quarter before. Certainly, we think about the coming quarter, but we know that the industry could come under pressure again. So we still think we have some runway and some ability.

We think the industry is going to give us the ability to continue to get even better utilization with our incremental adds and pricing, and we feel pretty good about that at the moment. So consolidating, probably not something that we would look seriously at ourselves..

I appreciate the color. Just one final question, to make sure that we don’t get ahead of ourselves on Q4 revenues, so 85% of your fleet active last quarter, 95% now. So that’s up 11%, 12% sequentially. A little bit better pricing, but then you’re heading into holiday season.

So is the implication you could see pressure pumping revenues up low-double digits? Or are you kind of more conservative than that?.

Well, we’ll always be more conservative. I mean, you just mentioned it back that’s involved. We don’t currently from our customers have any idea that there’s going to be an extended holiday shutdown. Christmas and New Year’s come on a Monday, which is – which I can guarantee that, by the way, and that’s mildly better for long jobs.

If those holidays are in the middle of the week, you can’t work for two day, shutdown and work for two more days. So it’s mildly positive. So – but we’re – we don’t give revenue guidance, as you know..

Okay. I just kind of laid out what else is going..

We understand and we appreciate it, Ken..

We’ll go next to Thomas Curran with FBR..

Hey, good morning guys. Thanks for squeezing me in. I really don’t looking being greedy, we’re going to have you guys [indiscernible] in about two weeks. But I guess, just a few quick follow-ups on prior lines of questioning. First, on frac pricing.

Since you guys have been in the spot market since the beginning of the upturn, where is your average spot pricing at this point relative to where it bottoms? And how does that compare to the leading edge?.

Tom, where spot pricing is today is probably pretty close to the leading edge. There’s a little bit of a lag but not enough to try to analyze and tell you about. Pricing is probably up 65% from the trough, something like that..

We’d like to get about that here..

Yes..

And then turning to frac sand.

For your standard measure of intensity, which is frac sand consumption per stage, how much did it sequentially increase in 3Q?.

Frac sand usage per stage actually declined slightly. Frac sand per stage declined second quarter to third quarter in the mid-single digits. Total sand usage was much higher as was total stages, but sand per stage declined from second to third quarter..

And could you expound upon some of the factors behind that reversal in trend? Have you started to see some of your biggest customers going to more efficient designs? Was it a disruption issue in terms of delivery? Maybe just some color around what was behind that decrease..

Yes. Tom, we have looked at it and asked about it. It is not meaningful in a sense that it does not indicate a trend one way or the other. And what’s happening, it was a few customers in a couple of basins that just had different jobs. Remember, we do not have major customers who are 25% or 30% of revenues. So it was just job mix..

Okay. And then last one for me.

When it comes to your major customers, has your single largest customer changed from who it was exiting last year? And if so, could you tell us who the new largest customers?.

We don’t have any customers that account for more than 10% of revenues. And so that’s a nice way of telling you we’re not going to tell you who are largest customer is. But we’ve got a diversified customer mix. It’s – whoever our largest customer is, is a pretty small percentage of revenue..

Okay.

So nothing to necessarily read into how that mix might have evolved even if it has or it sounds like you’re saying?.

Correct, correct. In an answer to an earlier question, our customer mix pretty much nears the drilling rig count with the exception that we do have more revenue coming from private E&Ps. But again, it’s not – until these things become a trend, they’re aren’t meaningful to us or we don’t think to the analyst community either..

Okay. I’ll stop here. We’ve already gone over an hour. I appreciate the generosity with your time. And we’ll see you guys..

Okay..

[Operator Instructions] We’ll go to our next question from Jud Bailey with Wells Fargo..

Thanks, good morning. Thanks for squeezing me in. Understanding frac is the biggest and it drives your EBITDA, but I wanted to ask about your non-frac business if I could. Just coiled and thru tubing, how you kind of see those businesses progressing over the next few quarters of 2018, particularly with a, call it, flattish rig count.

How do you think we should think about those businesses next year in an environment where completions are slightly up, rig count flat, flattish or call it, from a margin and revenue standpoint?.

Jud, this is Jim. That’s – at the start of the question, I was hoping for an answer. Coiled – because we’re saying our other completion businesses have lagged pressure pumping coming out of the downturn for reasons that we all – everybody in this call knows and understands.

Coiled tubing has started to improved recently, and it usually does lag pressure pumping both up and down. Having said that, there are probably some secular challenges to coiled tubing because of its application and completions and the fact that it doesn’t work as well with longer laterals.

There are ways you can get it further out, but it’s – it can be a bit challenged by that. So we think it’s going to continue to improve because it’s a vital completion business, just not to the extent that pressure pumping has. Thru Tubing Solutions, strong performer, good margins, and that should continue.

I mean, if you’re looking for a way to forecast Thru Tubing Solutions, it would be how many frac stages are being done in the United States, maybe the highest correlation between Thru Tubings revenue and anything else. Some of our other businesses have been more challenged.

The rental tool business, just because of the lower demand for drill pipe, has had a tougher time than the second and third largest businesses, being coiled tubing and Thru Tubing Solutions. Kind of the best we could offer right now..

I just might – just add about Thru Tubing Solutions. The reason it hasn’t balanced off the bottom as hard as pressure pumping is because it didn’t go down as far. It’s not as impacted due to the nature of the specialized services and things like that. So they historically have outperformed the rig count changes, and I expect they will continue to.

But again, it’s a little bit more steady, less volatile than some of the other completion service lines..

Okay. I’ll cut it off there and turn it back to you guys. Thank you..

All right, Jud. Thanks..

We have no further question at this time. I’d like to turn it back over to Jim Landers for any additional or closing remarks..

Okay. Thank you, Stephanie, and thanks to everybody for calling in and your interest. We appreciate the interest in RPC and look forward to seeing you all soon. Have a good day..

This concludes today’s call. As a reminder, in two hours, this call will be available for replay on www.rpc.net. Thank you for your participation, and you may now disconnect..