RPC Inc (RES) 2017 Q2 法說會逐字稿

Good morning, and thank you for joining us for RPC, Inc.'s Second 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. (Operator Instructions)

I would like to advise everyone that this conference call is being recorded. Jim will get us started by reading the following 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.

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 provide 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 have 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 historical lows set during the second quarter 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 a $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 increases -- 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 '17 compared to $1.5 million in the same period last year. This increase is 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 improve 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 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 headcount increased to 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 the 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.

(Operator Instructions) And we'll take our first question from Marc Bianchi with Cowen.

I guess, first question, as a -- 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. 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 all 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 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 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 some more price, is it unreasonable to think about $100 million improvement in revenue from second to third in the pumping business specifically?

I have to quantify (inaudible). Didn't quantify 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, okay. Fair enough. And then just on the margin potential, 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.

And we'll take our next question from George O'Leary with TPH & Co.

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?

We -- our operations people have done a tremendous job being able to try to flow 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 "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 and [since your] last few days and obviously given your presence in pressure pumping, coiled tubing and then Thru Tubing Solutions business, curious, where you guys are seeing from a well intensity standpoint, both from potentially a proppant pumped for your business and a -- 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 the good data in front of us a. 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.

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

I guess following up on the pricing question, are we at the point in which it's [safe to start] thinking about contracting pricing? Or is it still early to move a little bit higher to thinking about entering into more fixed-price contract?

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

Okay. And then, I guess, 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 check boxes, returns and payback periods being fastened up, are we at the point in which a new build would be justifiable, if oil prices were not -- if they were at a more stable point?

I think, we will certainly be much more comfortable if that were 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 '18 and what the future might hold. And we like the fact that oil prices have firmed a bit this morning in the recent days. 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 seem to -- continue to proceed. But at this point, no decision has 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 sand for? And I guess, could you talk about whether your customers are foreshadowing a shift in the regional light 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 -- well, 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.

And we'll move next to Waqar Syed with Goldman Sachs.

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 onetime?

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, it is a quarter-to-quarter decision. So I would not -- this is not -- 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 will continue to be that way.

Okay. And then in terms of spot [exporter] versus contracted fleet, could you give us some sense on how much of your pumping fleet has been kind of termed out maybe like 6 months type duration or longer versus that which is more in -- on a monthly basis about a 2 well or pad-by-pad?

Waqar, this is Jim. The most useful way to think about our pressure pumping fleet is that it's 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 best way to think about it. But contracts the way that we think about them in this industry, we do not have any of right now.

And you've (inaudible) 6 months. 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 terms of the contract or it's just the customer base? Why is that?

Pricing's not yet attractive enough, and it may be a symptom of low commodity prices or uncertainty about commodity prices from our customers point of view.

And we'll go next to Ken Sill with SunTrust Robinson Humphrey.

Just wanted to close the loop on that 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 that -- how do I close that loop?

The way we think about pricing is, we -- it's been a long time since 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 the -- at pricing today and something were to happen to 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.

Yes. I know, I appreciate that because -- yes, my impression is a contract in a lower oil price environment is the starting point for negotiations. So I like the capital discipline, and there's 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, there -- again, a lot of it is relationships with customers. Certainly, they're saying that there's lots of work they would love -- they need to work with us. They are talking about projects and plans through the end of the year, and they are including us in the discussion. So from that perspective, we are "booked up," but 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 out through the end of the year.

Yes. And one other 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 got more wells lined up. How does that affect your frac count? I know you guys were 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, you got 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 in -- what that leads to is much higher utilization, which is a positive. Now 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 17 with any more visibility than it did before because customers can always cancel 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.

I appreciate that. I was looking at my calendar before the call trying to figure out. Kind of summer's over here.

We'll take our next question from Rob MacKenzie with Iberia Capital.

Follow-on question to the train of thought gentleman. Jim, when you say that 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, low 80s in terms of percentage, but that's effectively 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 still very high. It's probably about -- I think the number is probably 72%. So it's called low 70% range is on 24-hour work rather than 80%, which we would have said 3 months ago.

Okay. How have you guys seen the impact of Schlumberger aggressively reactivating equipment, BJ kind of re-entering the market 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 refer to as well as some other fleet adds, demand is still higher than supply at this point.

Okay. 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 to just kind of wait and see type approach?

More driven by commodity price uncertainty. We think completion activity is going to be strong for a while at this rig count. We think there's plenty of work for our fleet right now with the idea of making a capital commitment to buy new equipment it not being here for 6 to 8 months. Some of the components that we really want for our high-quality fleet, continuous duty engines and pumps and 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 seeing lots of people reactivating equipment. So there's a lot of dynamics at play. We would prefer to see what the impact is. There's no way to know immediately as all of this equipment's been 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. Yes, there's no rush. And 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 '14 as a 100, where would you say pricing is on average right now?

65. 65.

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

Remembering though that the nature of the work has changed a lot over the past 3 years. But yes.

We'll go next to John Daniel with Simmons & Company.

Just a few for me. Jim, even though you guys already own a Wisconsin sand mine. Are you considering any stand-up line 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?

Bakken -- in the Bakken, we have 2 fleets working now, John. That's where some of the activated equipment is now in second quarter. And in talking to our operations guys there just recently, they believe that there's a high enough drilled but uncompleted well count. That's going to be a good place for us in the coming months ex any weather issues that come up.

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 or 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 and then the ability of these guys that, that customer subset to sustain current activity levels, should we stay in this $45 to $50 band, $45, $50 band?

People always do some saber rattling. We don't have firm indications of any customers who are -- any smaller E&Ps, that's your question, dialing back to the 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 of having to get new capital as others might be. So other things equal be, their activity might be a little more sustainable.

Okay. Fair enough. And then, 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 expect Q3 versus Q2? Should we see a step-up in revenue?

I guess, mathematically, that might be the case. But often times, there's 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.

We'll go next to Chase Mulvehill with Wolfe Research.

So maybe if you've answered some of these questions, I apologize. I was on another call. I just hopped over. Your active fleet count, where did that end 2Q out?

Yes, we had 80% that was manned and ready to go into the quarter.

All right. 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?

We did say probably something closer to 90%, 95% by the end of the third quarter. But the 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?

Not -- nothing to any significant degree. No.

Okay. All right. And Jim sometimes you give us the sand intensity. If you gave that before, we can just -- 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, did the moment pricing slow on sand? I mean, what have you seen kind of more this month?

Yes. Overall, for us, the price of sand increased sequentially mid-single digits between first and second quarter. And that's not a huge -- 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 it in front of me, Chase. It will be in the Q it is filed shortly. I just don't have it in front of me. Apologize.

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 -- what were 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 it, right?

Yes. (inaudible) We just know we're doing the best we can right now.

(Operator Instructions) We'll go next to Matthew Johnston with Nomura.

So you're not at the point today where you're ready to commit to new build 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 the various components we use and the choices you have to make. I would say, at this point, 6 to 8 months probably lead time.

Okay, 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 utilization standpoint?

Yes. We are -- we think there is -- 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 off a very low, low base. So we see opportunity. We think -- we talked earlier about multi-well pad. 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's a drag, especially for our rental tool service lines. We think the rental tool -- that 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.

And we'll go to John Daniel with Simmons & Company.

Just 2 follow-ups. Jim, are you guys seeing any signs that customers are migrating back to sliding sleeves technology?

We don't need detail on that. I mean, whether they are in a -- we don't really know.

Okay. And then you noted the 6 to 8 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 new build 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 are stuck at a $50 oil price?

John, just using your numbers, which I think are really good, announced and known new build capacity still doesn't get us in an oversupply 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?

Yes, we keep looking, but private equity always wins.

And we'll go to Ken Sill with SunTrust Robinson Humphrey.

Yes. Just wanted a quick clarification. The 10% sequential increase in sand, was that total sand volumes bump through is that on a per well basis?

That was on a per stage basis.

On a per stage basis?

Yes.

Okay. So I got it wrong, both ways.

That's all right. Thanks, Ken.

And at this time, I'd like to turn the call back over to Mr. Landers for any additional or closing remarks.

Thank you, operator. And everybody, thanks for calling in today. We appreciate your attention and the interest in the company and enjoyed the dialogue. We will talk to everyone again soon. Thanks.

Thank you. And that does conclude today's conference. This call will be replayed on www.rpc.net within 2 hours. Thank you for your participation. You may now disconnect.