James C. Landers - RPC, Inc.

Richard A. Hubbell - RPC, Inc.

Ben M. Palmer - RPC, Inc.

Marc Bianchi - Cowen & Co. LLC George O’Leary - Tudor, Pickering, Holt & Co.

Securities, Inc. Praveen Narra - Raymond James & Associates, Inc.

Waqar Syed - Goldman Sachs & Co. LLC Ken Sill - SunTrust Robinson Humphrey, Inc.

Rob J. MacKenzie - IBERIA Capital Partners LLC John Daniel - Simmons & Company International Chase Mulvehill - Wolfe Research LLC Matthew Johnston - Nomura

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.

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 issued 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 the press release for any reason, 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 second quarter of 2017.

The U.S. domestic rig count increased at a record rate from the historic low set during the second quarter of last year.

Our positioning and preparation during the recent downturn allowed us to capture the benefits of improving conditions. RPC's strong market presence in the Permian Basin and the reactivation of some of the company's idle equipment also contributed to our results.

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

Okay. Thanks, Rick.

During the second quarter, revenues increased to $398.8 million compared to $143 million in the prior year. Revenues increased due to higher activity levels and pricing for our services, higher service intensity, and a slightly larger fleet of in-service revenue-producing equipment.

EBITDA for the second quarter was $110.3 million compared to a loss of $19.1 million for the same period last year. Operating profit for the second quarter was $67 million compared to an operating loss of $75.2 million for the same period in the prior year.

Diluted earnings per share were $0.20 compared to $0.23 loss per share in the prior year. Cost of revenues during the second quarter was $254 million, or 63.7% of revenues, compared to $127 million, or 88.8% of revenues, 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 costs.

Selling, general and administrative expenses were $40.3 million in the second quarter compared to $36.5 million in the same period last year. These expenses increased due to higher compensation costs, as well as other expenses consistent with higher activity levels.

As a percentage of revenues, these costs decreased to 10.1% compared to 25.5% in the same period last year, due to the leverage of higher revenues over fixed expenses. Depreciation and amortization were $41.3 million during the second quarter of 2017, a decrease of 26.7% compared to $56.3 million for the same period last year.

Net gain on disposition of assets was $3.8 million in the second quarter of 2017 compared to $1.5 million in the same period last year. This increase was primarily due to the sale of operating equipment related to our oilfield pipe inspection service line.

Our Technical Services segment revenues for the quarter increased by almost 200% compared to the second quarter of the prior year due to improved pricing and higher activity levels. Operating profit was $70.9 million compared to an operating loss of $65.7 million in the same period last year.

Our Support Services segment revenues for the quarter increased by 13.3%, and operating loss decreased 53.4% 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, I'll discuss briefly some sequential results.

Sequentially, RPC's second quarter revenues increased by $100.7 million or 33.8% compared to the prior quarter. Revenues increased due to improved pricing for our services and higher activity levels, as well as a slightly larger fleet of in-service revenue-producing equipment.

Cost of revenues increased by $37.8 million or 17.5% 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 72.5% in the prior quarter to 63.7% due to pricing improvements and operational leverage from higher activity levels.

Selling, general and administrative expenses during the second quarter of 2017 increased by $3.1 million or 8.4% compared to the prior quarter due to increased costs consistent with higher activity levels. SG&A expense as a percentage of revenues decreased from 12.5% in the prior quarter to 10.1% this quarter due to leverage of higher revenues over relatively fixed costs.

RPC's operating profit during the second quarter of 2017 was $67 million compared to $1.6 million in the prior quarter, an increase of $65.4 million. RPC's sequential EBITDA increased from $46.5 million in the first quarter to $110.3 million in the second quarter, and the EBITDA margin improved from 15.6% to 27.7%.

Our Technical Services segment generated revenues of $385.5 million, 34.7% higher than revenues of $286.2 million in the prior quarter. Operating profit improved to $70.9 million compared to $9.2 million in the first quarter.

Our operating margin in this segment increased from 3.2% in the prior quarter to 18.4%. Our Support Services segment generated revenues of $13.3 million, 12% higher than revenues of $11.9 million in the prior quarter.

Operating loss decreased to $3.3 million in the second quarter compared to $5.2 million in the prior quarter. As of the end of the second quarter, RPC's pressure pumping fleet remained unchanged at 925,000 hydraulic horsepower, of which approximately 80% is manned and available to work; this compares to 70% at the end of the prior quarter.

RPC's total head count increased 11.8% during the second quarter. Our second quarter 2017 capital expenditures were $18.9 million.

We expect full year 2017 capital expenditures to be approximately $100 million, directed primarily toward maintenance of our equipment. With that, I'll now turn it back over to Rick for some closing remarks.

Thank you, Ben. We currently see indications of high customer activity levels through the end of 2017.

We are closely monitoring recent fluctuation in oil prices and their potential impact on customer drilling and completion plans. And therefore, we remain cautious about large capital commitments at this time.

Yesterday, our board of directors declared a $0.06 per share dividend based on RPC's improving operating results and strong balance sheet. Thank you for joining us for RPC's conference call this morning.

And at this time, we will open up the lines for your questions.

Thank you. I guess, first question, as you often provide the percentage breakdown for the businesses.

I was hoping we could start with that, Jim.

Sure, Marc. Absolutely.

So, the numbers I'm about to give are percentage of consolidated revenue that our largest businesses account for. The largest is pressure pumping.

It was 63.6% of consolidated RPC revenues. The second largest is Thru Tubing Solutions, which was 18.0% of consolidated revenues.

Third largest is coiled tubing, which was 6.5% of revenues. We also talk about nitrogen, which was 2.3% of revenues, and rental tools, which was 1.6% of consolidated RPC revenues.

Okay. That's great.

Thanks, Jim. And I guess, so that would say your pressure pumping revenue grew about 40%.

Based on the prepared remarks, it sounds like the active fleet grew by about 15%, if I'm just taking the – or the manned and available improvement there. So, fair to say the balance is oil price?

No. It's a little more evenly split between pricing and some more utilization.

Okay. And as we look forward to the third quarter, I suspect you'll get the benefit of some more reactivation.

But how to think about how much of a benefit you could be getting additionally from price, perhaps additionally from service intensity, just trying to think about the revenue potential there as we roll into the third quarter?

Well, in terms of reactivation, we talked about last quarter that we had plans to try to roll everything out, sort of steadily between the end of the first quarter and the end of the third quarter, and we're still executing on that program. So, close to all of the capacity, probably more like 95% will be implemented by the end of the third quarter, if we hold to our plan.

Right now, we expect that most of that reactivation on that additional equipment will happen probably later in the third quarter. So, with respect to your question, where we're going to get more – what's the opportunity for additional revenue from a pricing perspective and performance perspective, clearly, the demand for pressure pumping as we've all read and seen has been the strongest and that's the case for us.

So, we think there are opportunities with some of our other service lines to increase their revenue potential as well. So, we're hoping that's going to help us some.

And we think pricing, at this point, our utilization is very strong as you can tell by the numbers and we hope that there might be some additional pricing, but we are not counting on that at this point in time for pressure pumping.

Sure. That's a good conservative approach.

I guess maybe if I just look at the revenue improvement in pumping, it was about $70 million. Assuming that there's some more reactivation, kind of faster pace of reactivation helping your revenue in the third quarter, maybe at similar price, is it unreasonable to think about $100 million improvement in revenue from second to third in the pumping business specifically?

I haven't quantified – didn't quantify it for you there. But note that I did say that the reactivations in the third quarter will be later in the quarter, not earlier, so.

Okay. Fair enough.

And then just on the margin potential, your very strong incrementals helped a lot by price, I suspect. Would you expect that incremental margin to settle back into something that we've seen in the fourth and the first or should it remain at that level of kind of 60% that we saw in the second quarter?

Marc, this is Jim. Incrementals will continue and continue to be strong.

This was a very strong incremental quarter, so – sort of starting from a lower base, et cetera. So, I would expect incrementals, while continue to be good, to be more modest in coming quarters.

Fair enough. Thanks.

I'll turn it back.

Thanks, Marc.

Good morning, guys.

Hey, George.

So, the commentary around leading edge pricing was very helpful. I guess, maybe could you help frame about how much of the horsepower you guys have that's active today?

That 80% is still kind of on its way moving up towards leading edge. So, do we still have some of the horsepower that's sitting at lower prices that may actually migrate up in the third quarter?

Our operations people have done a tremendous job of being able to try to control and get pricing. Fairly, it varies some, but I would not say there's any particular amount of equipment that's significantly lagging.

We do not have any firm, long-term commitments on pricing with any of our customers. So, I would say, we're very much quote-unquote spot on with our pricing.

So, we're still enjoying the benefits of that and we've got a good program in place to monitor the pricing and the quoting activity. So we feel that, overall, it's reasonably consistent across the fleet.

Great. And then I heard some interesting comments around well intensity over the last few days.

And obviously, given your presence in pressure pumping, coiled tubing, and then the Thru Tubing Solutions business, curious what you guys are seeing from a well intensity standpoint, both from potentially proppant pumped for your business and what you're seeing on the lateral length front from your customers?

George, this is Jim. Service intensity measured as proppant pumped continues to rise, so probably around a little north of 10% for the quarter sequentially.

And we don't have a good data in front of us, but anecdotally, at least we know from the field that lateral lengths continue to increase. So, proppant per stage is higher and lateral lengths are continuing to grow, which yields more proppant per well from both those variables.

Very helpful. Thank you, guys.

Sure.

Thank you.

Hi. Good morning, guys.

Hi, Praveen.

I guess following up on the pricing question, are we at the point in which it's time to start thinking about contracting pricing or is it still – do we still need to move a little bit higher to think about entering into more fixed price contracts?

Customers ask a lot about that. But at this point, we've not seriously entertained or going into any intense negotiation around pricing on a longer-term basis.

Okay. And then, I guess I appreciate the comments on the oil price being in flux and potentially changing what the outlook might look like.

I guess, in terms of all the other checkboxes, returns and payback periods being fast enough, are we at the point in which a new bill would be justifiable if oil prices were not – if they were at a more stable point?

I think we would certainly be much more comfortable if that was the case to place orders, but we're trying to remain disciplined. We still have additional equipment for us to put out into the market and see what happens over the coming weeks and quarters, and to make that decision.

So, we're comfortable right now with the capacity that we have and the position we're in and – but we're studying it all the time. Obviously, we're beginning – like many people right now, we're beginning to think about 2018 and what the future might hold, and we like the fact that oil prices have firmed a bit this morning and in recent dates.

But we would love it to have a 60 handle rather than a 50. But we'll watch it, talk to our customers, see how things continue to proceed, but at this point, no decisions have been made.

Okay. Perfect.

And then last one for me. Do you have in front of you, I guess, the percentage of jobs that RPC provided (19:31)?

I guess could you talk about whether your customers are foreshadowing a shift in the regional wide mix?

Praveen, this is Jim. We actually don't have that number right in front of us, but the majority of the sand we pump is sand that we provide.

It's just part of our business model. That does kind of ebb and flow based on customer preferences and what they – the customer preferences.

Right now, on the regional sand issue, everyone's talking about it. We haven't used any, our customers haven't asked us to use any yet.

But, I mean, it's kind of self-evident that good sand that can come to you without the use of a railroad is a good thing. We just don't have good information on projections on how much will be used or how much we're going to use.

So, we just don't have good information on that at this point.

Perfect. Thank you guys very much.

All right, Praveen. Thanks.

Thank you. Good morning and great quarter, congrats on that.

My question relates to capital allocation, you announced a dividend. Should we consider that to be like a regular dividend now or is that kind of one-time?

Well, we paid a dividend at year end, and obviously, we've announced a dividend for this quarter. But we're looking at it, at this point, as it is a quarter to quarter decision.

So, I would not – this should not be characterized as a regular quarterly dividend at this point.

And how about share buyback? What's the strategy there?

We are always opportunistic. We did do some buybacks this quarter.

We did them earlier in the quarter. And given the move in our stock price, that appears to be – that it was opportunistic and we'll continue to be that way.

Okay. And then in terms of spot exposure versus contracted fleet, could you give us some sense on how much of your pumping fleet has been kind of termed out, maybe like six months type duration or longer versus that which is more on a monthly basis well to well or pad by pad?

Waqar, this is Jim. The most useful way to think about our pressure pumping fleet is that it is all on spot right now.

Now, we may have – we have handshake agreements or agreements to do a series of wells or for a – a series of wells is the best way to think about it. But in contracts, the way that we think about them in this industry, we do not have any right now.

And you referred to a six-month. There's no kind of commitment like that.

I mean, there may be an understanding with the customer that we're working with them on a project that might last a few weeks, a month or something like that, but we're not going out any significant term beyond that.

And is that because you don't want that, you don't trust the term of the contract or it's just the customer base? Why is that?

Pricing is not yet attractive enough and there may be a symptom of low commodity prices or uncertainty about commodity prices on our customers' point of view.

Okay. Great.

Thank you very much.

Thanks, Waqar.

Hi. Good morning, gentlemen.

Hi, Ken.

Just wanted to clear up on the last question. So, it sounds like you think you're pretty close to replacement cost pricing, and yet you don't think pricing is good enough to sign long-term contracts.

So, I'm kind of curious, how do I close that loop?

The way we think about pricing is, we – it's been a long time, so we thought about locking in pricing for any of our fleet. We would like to think maybe it could get better.

We're not signaling that we think it's going to move up significantly from here, but I think everybody is cautious. Our customers would love to lock us in at lower pricing maybe than we are right now, but we're not interested in that.

We think there is an opportunity for pricing to move up. So, we are continuing to remain nimble and be able to respond to what's going on in the market.

If we were to lock in at pricing today and something were to happen to the oil prices, and it was moved down significantly, I am certain that our customers would come to us and say, we got a contract, but we need to talk about our pricing. So, we prefer to remain spot and work the relationships with our customers, and be able to have the flexibility to respond to what's in the marketplace.

So, we're continuing to remain on spot and will for the time being.

Yeah. No.

I appreciate that. Yeah.

My impression is a contract in a lower oil pricing environment is the starting point for negotiations. So, I like the capital discipline and there's a lot of interesting things going on.

You did make the comment that customers would want to lock you in at lower prices. Is there any interest from customers at these prices or is it just, they're just kind of in the same place you are, given the uncertainty in commodity prices?

Probably same place we are.

And then you guys said, you got pretty good visibility through the end of the year. Are you guys booked up through Q4 already or most of the way through Q4?

Well, again, lot of it is relationships with customers. Certainly, they're saying that there is lots of work – they would love to continue to work with us.

They're talking about projects and plans through the end of the year, and they're including us in the discussion. So, from that perspective, we are quote-unquote booked up, but again, it's all subject to when the time comes and when the time comes to say, we're ready to get started on this next well.

So – but we do feel good, there are lot of active discussions and coordination with our existing customers which, from that perspective, would equate to us being pretty much booked up through the end of the year.

Yeah. And one another question, so that's something I'm curious about, if you're seeing any trends, particularly in West Texas?

I know this has already happened up in the Rockies, but trends in more wells per pad and given the fact that if you're doing pad drilling, you get more wells lined up. How does that affect your frac count?

I know you guys, we're sitting here late-August, you probably got a pretty good calendar for what you know is going to happen, plus or minus for the next 60 days. But do these pads kind of extend your visibility?

Are you seeing – not really seeing yet a change in the number of wells per pad?

Ken, this is Jim. In the Permian Basin, we are definitely doing more pad drilling and we are participating in pads that have many more wells to them, and that's a positive from a lot of points of view.

And what that leads to is a much higher utilization, which is a positive. Now, if there's only a quantity of net footage to be drilled, maybe it gets done more quickly, but right now, we're not second guessing anybody.

It looks like pad drilling and many more wells per pad is a net positive for us and it's helping us keep the calendar more full. That doesn't tell us what we're doing on December 17th with any more visibility than it did before, because customers can always cancel it, if the price of oil falls.

And you just mentioned this being late-August, it's actually late-July. So, let's not get ahead of ourselves too much.

So, we still feel good about the third and fourth quarters, whichever month we're in.

Yes. I appreciate that.

I was looking at my calendar before the call started to figure out if kind of summer is over here. But, thank you and I'll let somebody else ask question.

All right, Ken. Thank you.

Thank you. A follow-on question to the string of thoughts, gentlemen.

Jim, when you say the 80% of your frac fleet is manned and available, how should we think about the utilization of that equipment? And also, what percentage of that might be working kind of 24/7 these days?

Rob, this is Jim. That equipment is working basically at full utilization.

I mean, the number is upper-70s, lower-80s in terms of percentage, but that's effectively in full utilization. And actually, the percentage of that fleet that's on 24-hour work is a little bit less than it was this time last quarter.

So, it's still very high. It's probably about – I think the number is probably 72%, so let's call it low-70% range.

It's on 24-hour work rather than 80% which we would have said three months ago.

Okay. How have you guys seen the impact of Schlumberger aggressively reactivating equipment, BJ kind of re-entering the market and being, from what we hear, pretty aggressive on bidding.

How are they affecting the pricing dynamic and the utilization in the market? Are you guys seeing much there?

No. Thus far demand for pressure pumping equipment is – and services improves and logistical capacity demand is higher than supply, even with the reactivations you referred to as well as some other fleet adds, demand is still higher than supply at this point.

Okay. Thanks.

And then coming back to kind of the hesitance to build new equipment, is some of that, as we've heard on Wall Street, worry about the rig count and the completion count dropping from here or is that just more prudent kind of wait-and-see type approach?

More driven by commodity price uncertainty, but we think completion activity is going to be strong for a while at this rig count. We think there is plenty of work for our fleet right now, but the idea of making a capital commitment to buy new equipment is not being here for six to eight months.

Some of the components that we really want for a high quality fleet, continuous duty engines and pumps from some of those manufacturers, that equipment is in short supply right now, so that lengthens the order to delivery process. And we just don't know what commodity prices are going to be in March or April, and as Ben alluded to earlier, they start with a 4, not a 6 today.

But I would say there is a little bit of that wait-and-see as well. I mean, you're talking about we're all hearing about and seeing lots of people reactivating equipments.

So, there is a lot of dynamics at play. We would prefer to see what the impact is – there is no way to know immediately as all of these equipments being reactivated.

But we would rather see that, assess what we believe the impact is through our quoting and discussions with our customers, and then make the decision. There's no rush.

Again, we have additional capacity to put into place that will – that is generating nice returns at the moment. And we hope, and at this point, expect that to continue, but who knows 12, 24, 36 months from now.

So, we're going to remain disciplined on that front.

Makes sense. And then my final question comes to frac pricing.

If we were to index kind of third quarter 2014 as 100, where would you say pricing is on average right now?

65.

2014, yes.

65.

65? So there's a lot room to go?

Remembering now that the nature of the work has changed a lot over the past three years, but yes.

Okay. Thanks, guys.

I'll turn it back.

Thanks, Rob.

Thank you. Just a few for me.

Jim, even though you guys already own a Wisconsin sand mine, are you considering any sand mine development projects in West Texas at this point?

No.

Okay. Can you speak to how many fleets you've got working in the Bakken, and just speak to expected utilization in that region in the back half of the year?

In the Bakken, we have two fleets working now, John. That's where some of the activated equipment (33:11) in second quarter.

And talking to our operations guys there just recently, they believe that there is a high enough drill, but completed well count, that's going to be a good place for us in the coming months, ex any weather issues that come up.

Okay. Fair enough.

Just a couple of quick ones here. Are you seeing any signs from your customers, specifically those who are either private or like the smallest of Small Cap E&Ps, any indication that some of them might consider dialing back activity in Q4?

And then just separately, how would you characterize your confidence in the ability of these guys, that customer subset, to sustain current activity level should we stay in this $45, $50 band?

People always do some sabre rattling. We don't have firm indications of any customers who are – any smaller E&Ps, that's your question, dialing back to activity in the third and fourth quarter.

In general, they are less dependent on the vagaries of the public markets than some of the big public companies. So, they may not be as concerned with having to get new capitals, others might be.

So, other things equal, their activity might be a little more sustainable.

Okay. Fair enough.

And I guess final one for me. Just given that most of the equipment reactivations within frac are expected to occur at the end of Q3, should we therefore assume that you would expect faster revenue growth in Q4 versus Q3 than what you expected Q3 versus Q2?

Should we see a step up in revenue?

I guess, mathematically, that might be the case. But often times, there is a bit of a slowdown in the fourth quarter due to holidays and things like that.

So, at this point, it's too early. People aren't talking about vacation or holiday calendars at this point, but mathematically that might be the case, but we're not sure whether that will occur or not.

Okay. All right, gentlemen.

Thank you. Good quarter.

Thank you.

Okay. Thanks, John.

Appreciate it.

Hey. Good morning.

Hey, Chase. Good morning.

Hey, Jim. So, maybe if you've answered some of these questions, I'll apologize.

I was on another call, I just hopped over. Your active fleet count, where did that end 2Q at?

We had 80% that was manned and ready to go end of the quarter.

Okay. All right.

And then, when we think about all your horsepower fully deployed at the end of the third quarter, how much of that is going to be working in the Permian?

Well, we did say probably something closer to 90, 95 (36:12) by the end of the third quarter, but in terms of the Permian...

A little over half, Chase, probably.

Okay. All right.

And then, when as we think about 3Q margins, I'm trying to understand the margin profile as we get into next quarter, are there any kind of one-offs that we should be aware of, either positive or negative, sand contracts, resetting, anything like that?

Nothing to any significant degree. No.

Okay. All right.

And Jim, sometimes you give us the sand intensities. If you gave that before, we could skip that.

But could you give us the sand intensity for 2Q?

Sure. We did talk about it before, but it's an easy answer.

It's a quick answer, a little over 10% increase.

Okay. All right.

And sand pricing trends throughout the quarter, at the moment (37:10) pricing slow on sand? And what have you seen kind of more this month?

Yeah. Overall, for us, the price of sand increased sequentially mid-single-digits between first and second quarter.

And it's not a huge number, and we don't see it accelerating in third quarter in spite of large volumes. We just feel that there's a lot of available sand out there, so.

Okay. All right.

And for Technical Service margins, what were EBITDA margins in 2Q? We don't have the D&A yet, and maybe it's just helpful to give us the D&A maybe by segment?

Yes, and I apologize. I don't have that in front of me, Chase.

Okay. All right.

It will be in the Q that's filed shortly. I just don't have it in front of me.

Okay. All right.

And if we think about TS margins for 2Q, if we think about April versus June, what was the spread of the margins between April and June for this segment?

In other words, what were April margins – or what was the difference between April margins and June margins.

Or if you just want to give us June margins, but I'm assuming you probably don't have them.

Yeah, we don't have that one. Just know we're doing the best we can right now.

All right. Well, I think that's all that I have.

Okay, Chase. Thanks.

Thank you.

Thanks, Jim.

Hey. Good morning, guys.

Hey, Matthew.

So, you're not at the point today where you're ready to commit to newbuild equipment. But I'm curious, have you tested your supply chain yet or put any increase into your supply chain with respect to potentially building in the future?

And if you have, what do you think the lead time is, if you were to put an order in for another spread?

Matthew, we're constantly in contact with those folks, because of various components we use and the choices you have to make. I would say, at this point, six to eight months for lead time.

Got it. Okay.

And then just wondering if we could shift a little bit away from pressure pumping and maybe talk about the outlook for your other product lines from a pricing and a utilization standpoint?

Yeah. We think there is – I think I had indicated earlier, the pressure pumping clearly has seen the biggest push and demand, did have improvement from several of the other service lines, but we think there's additional upside for them in terms of revenue growth.

And given the low base upon which they were coming off Q1, their incrementals were very strong, but again, it's also very low base. So, we see opportunity.

We talked earlier about multi-well pads and we think that's been – the drilling profile, there's a lot of drilling going on. But with the multi-well pads, we think that's a little – there is a drag especially for our rental tool service lines.

We think the rental tool – the drilling companies are able to be much more efficient with the rental tools that they own. So we think, at this level of rig count activity, it's a bit of a challenge for that particular business of ours.

But we see some opportunity. We are hopeful that we'll see some nice improvement in the next couple of quarters with our other service lines other than pressure pumping.

Got it. Appreciate the comments.

Thanks, guys.

Sure.

Thanks, Matthew.

Hey. Thanks for throwing me back in.

Just two follow-ups. Jim, are you guys seeing any signs that customers are migrating back to sliding sleeve technology?

We don't have any detail on that. I mean whether they are or not, we don't really know.

Okay. And then you noted the six to eight months lead times for new equipment.

One would assume that the growing lead time reflects an effort by some of your competition to build new capacity. I'm just curious are you concerned at this point that we have now entered a more robust newbuild cycle?

And if so, just even though it won't hit for some time, how do you think about protecting the business, the margins, as you get into next year, particularly, if we're stuck at a $50 oil price?

John, just using your numbers which I think are really good, announced and known newbuild capacity still doesn't get us into an oversupplying situation at today's activity levels. So, that's why we feel good about third and fourth quarter, that and other reasons.

This is a capital-intensive and very speculative business though, and it will overbuild again. And so, the only way we can protect our margins is to think about long-term financial returns and manage the business that way, which is why we are not at this point participating in the building that's going on.

It doesn't mean we have a negative outlook on the business, it just means that it's uncertain and that is all that we can do.

Just given your returns focus, is it safe to assume that you guys will continue to shun M&A activity and let others do it?

Yeah. We keep looking, but private equity always wins.

Okay. Thanks, guys.

Sure.

Sure. Thanks.

Yeah. I just wanted a quick clarification.

The 10% sequential increase in sand, was that total sand volumes pumped or was that on a per well basis?

That was on a per stage basis.

On a per stage basis?

Yes.

Okay. See, I had it wrong both ways.

Thank you.

That's all right. Thanks, Ken.

Thank you, operator and everybody, thanks for calling in today. We appreciate your attention and interest in the company, and enjoy the dialogue.

We will talk to everyone again soon. Thanks.