Pioneer Energy Services' CEO Discusses Q2 2012 Results - Earnings Call Transcript

| About: Pioneer Energy (PES)

Start Time: 11:00

End Time: 11:51

Pioneer Energy Services (NYSE:PES)

Q2 2012 Earnings Call

August 7, 2012 11:00 a.m. ET

Executives

Anne Pearson – SVP & IR Counsel

Stacy Locke – President & CEO

Lorne Phillips – CFO

Analysts

Brian Uhlmer – Global Hunter Securities

James Rollyson – Raymond James

Michael Cerasoli – Goldman Sachs

Josh Lingsch – Simmons & Company

John Keller – Stephens

Mike Urban – Deutsche Bank

Daniel Burke – Johnson Rice

Jeff Geygan – Milwaukee Wealth Management

Operator

Good day, ladies and gentlemen. Thank you for standing by. Welcome to the Pioneer Energy Services Second Quarter 2012 Earnings Conference Call. (Operator Instructions). Following the presentation, the conference will be open for questions. (Operator Instructions) This conference is being recorded today, August 7, 2012.

I would now like to turn the conference over to Anne Pearson of BRG&L. Please go ahead.

Anne Pearson

Thank you, Erin, and good morning, everyone. Before I turn the call over to CEO, Stacy Locke, and CFO, Lorne Phillips, for their formal remarks, I have a few of the usual items to cover.

First of all, a replay of today’s call will be available and will be accessible by webcast by going to the IR section of Pioneer’s website and also by telephone replay. And you can find the replay information for both in this morning’s news release.

Just as a reminder, information reported on this call speaks only as of today, August 7, 2012, so any time sensitive information may no longer be accurate at the time of a replay. Management may make forward-looking statements today that are based on beliefs and assumptions and information currently available to them. While they believe the expectations reflecting in these statements are reasonable, they have no assurance that they will prove to be correct. They are subject to certain risks and uncertainties and assumptions described in this morning’s new release and also in recent public filings with the SEC. If one or more of these risk materializes or should underlying assumptions prove to be incorrect actual results may vary materially.

Also, please note that this conference call may contain references to non-GAAP measures. You’ll find a reconciliation to the GAAP measures in this mornings news release.

So, now I’d like to turn the call over to Stacy Locke, Pioneer Energy Services President and CEO.

Stacy Locke

Thank you, Anne, and good morning, everyone. Sorry for the brief delay. We were trying to get the webcast on our website working this morning since we have a new website and so we delayed this just a bit, and I’m not sure it’s even working yet but, anyway.

Joining me on the call this morning and sitting in for Red West, President of the Drilling Services segment, is Blaine David, our Senior Vice President of Operations. Blaine’s also in charge of our Colombian operation. Joe Eustace, President of the Production Services segment of the business, and Lorne Phillips, our Chief Financial Officer.

As most of you have seen by now, effective July 30 we’ve changed the name of the company to Pioneer Energy Services and we began trading under the ticker symbol PES. This is a culmination of a multi-year strategic plan. We now have all of our core businesses flying under the same name with the same brand look and feel, which we believe will strengthen the companies ability to cross sell the various services to each of the business clients from the different business line.

With respect to the second quarter, no real surprises from the revised guidance that we issued on June 25. Really the whole story in the second quarter was a coil tubing myth. Drilling was a little bit softer and it came in at the low end of our range that we provided in the original guidance, but both well service and wireline had record quarter in terms of revenue and EBITDA. In fact, Production Services as a whole, excluding coiled tubing, was up 7% in revenues. So it was a great quarter in all respects except for coiled tubing.

Now discussing coiled tubing. Let me first say that we have complete confidence in the senior management team and believe that the coiled tubing business is still a very good business and it’s still an important service for Pioneer to offer. Long term we think we will be one of the best service providers in coil just like we are in well service and in wireline.

In a nutshell, the issue this quarter in coil was onshore utilization. It averaged below 60% and that cannot sustain the high fixed cost in that business. In the first quarter by contrast, we were averaging close to 70% utilization and the margins were very good.

Part of the problem in the quarter, we had two units that had previously been on term transition over to spot. In addition, we moved one of those units out of the Marcellus, which became the weaker market down to South Louisiana, and we’ve made a number of important personnel changes. So we think the outlook is good for coil. It may take a quarter or two to get things sorted out but we’re still optimistic about coil in the medium term and long term.

The offshore aspect of the business where we have three units has performed very well, very stable, steady pricing, steady utilization. And we just this month in August added our fourth unit to the offshore so that brings our total unit count currently to 11 and we have two additional land units on order that we should receive in September that’ll become operational probably in October of this year. So we end the year at 13 units in coil.

Turning to the Well Servicing side of the business, it continues also to be very, very steady with utilization at 97%, average hourly rate approaching 600 at 592. Again a record quarter. Four well services. Thus far we’ve added 13 units and we have 102 operational units today with six more well servicing rigs on order. So we’ll end the year at 108 well service units.

Wireline, like Well Service, record quarter, continues to be our top margin producer. We’ve added 12 units there so far this year so we’re at 117 unit count today with three more on order for this year. So we should end the year in Wireline at 120 units.

Turning now to the Drilling segment. We have 65 rigs operating today at 88% utilization. That includes three of our new-builds that are out working. Two of those are 1,500 horsepower rigs in the Bakken and one is a 1,000 horsepower unit in the Marcellus. Presently we’re mobing our fourth new-build, which would be the sixty-sixth rig, to the Marcellus today. And the fifth new-build, or the sixty-seventh rig, will be moving at the end of next week also to the Bakken, and that’s another 1,500 horsepower. Performance overall on the new-builds has been excellent so we’re very pleased with that.

Looking at the rig fleet across the U.S., kind of the same story on which rigs are stacked. We still have a little softness in South Texas. Today we’ve got two rigs stacked. One of them is already contracted and will be going back to work. And then we have one of the Eagle Ford rigs, a 1,500 horsepower SCR rig that’s presently stacked but we’re bidding, have a number of bids out on that.

The two drilling rigs up in East Texas happen to be down today. We’ve had one usually working of the two but both are down today so that continues to be a weak market. As we mentioned in the last quarterly call, we have one down in the Alberta Bakken. That’s up in the northwest part of Montana. And that activity has really fallen off there. And we have the one rig still in the Houston yard that is about complete on its upgrade and we’re actively bidding that unit into West Texas.

And then we have the two units still down in Colombia. However, we have a lot of bids out that’s looking a little more promising. It looks attractive in terms of getting these rigs back to work and the day rates that they would obtain. So all in all, a pretty good market but some softness.

At this point, I’d like to turn the call over to Lorne to talk about some of the financials and then I’ll come back with a very brief current market outlook. Lorne?

Lorne Phillips

Thanks, Stacy. Good morning, everyone. So this morning we reported second quarter consolidated revenues of $229.8 million, which were down approximately 1% from the prior quarter and up 34% from a year ago.

Our net income was $9.7 million or $0.15 per diluted share and that compares to net income in the previous quarter of $14.2 million or $0.23 per diluted share and it compares with net income of $3.7 million or $0.07 per diluted share in the second quarter of last year. Our total adjusted EBITDA in the second quarter was $63.3 million, which is down 10% from the first quarter and up 40% versus a year ago.

I’ll start first by looking at the Drilling Services segment in detail. Drilling Services revenue totaled $119 million, which is 4% lower than the prior quarter and 12% higher than a year ago. The drilling operations in Colombia represented $22.5 million of that total, with six rigs operating and two rigs idle.

The second quarter gross margin for Drilling Services was $40.4 million, which was down about 6.5% from the prior quarter and our average drilling margin per day was $8,032, which was a decrease of $505 a day compared to the first quarter. The decrease in Drilling Service second quarter revenues, gross margin and margin per day as compared to the first quarter primarily relate to three items.

First, we experienced a decrease in turnkey contract activity. You’ll recall we had more than $8 million for turnkey work in the first quarter this year and as expected that was much lower in the second quarter, probably a little bit lower than we were thinking, even we produced about $400,000 in revenues.

The second item is a $1.4 million fuel cost reimbursement in Colombia that we received in the first quarter that was not an ongoing benefit into the second quarter. And finally, we incurred approximately $900,000 of stacking and mobilization expenses for two rigs in Colombia and three rigs in South Texas. Our average drilling rig utilization rate was 89% for the quarter and is currently 88%.

We have 57 of our drilling rigs currently working, of which 44 are under term contracts that range from six months to four years. Of the 38 rigs on term contract in the U.S., eight will be up for renewal by the end of this quarter, 12 are up for renewal in the fourth quarter, five are up for renewal in the first quarter of 2013, and six are in the second quarter of 2013, with seven rigs on term beyond that point. The average remaining term is eight months for drilling contracts in the U.S. and if you excluded the recently delivered new-builds, that number would drop to seven months in the U.S.

In Colombia, six of our eight drilling rigs are currently working under term contracts that expire at the end of 2012. And as Stacy discussed somewhat, we’re beginning negotiations with Ecopetrol to renew these contracts and we’re continuing to market our two idle drilling rigs in Colombia.

The drilling rig count I just went over do not include the new-build rig that’s currently mobilizing to the field and of course doesn’t include the remaining six new-build drilling rigs that will be deployed under term contracts. Of the remaining six rigs, three should be delivered by year-end and three in the first quarter of 2013.

As we renew contracts, the typical renewal term varies from 6 to 12 months. And at this time, more than 90% of our working drilling rigs are working on wells that are targeting oil.

Turning now to Production Services. The Production Services segment revenue totaled $110.8 million, which was up 3% from the prior quarter and was up 71% from a year ago. The acquisition of the coiled tubing business in late 2011 accounted for the majority of the year-over-year increase and the quarter-over-quarter increase reflects revenue contributions from five new well servicing rigs and seven new wireline units that we added during the second quarter of this year as well as we experienced moderately improved pricing and utilization in the well services and wireline businesses.

During the quarter, as Stacy mentioned, we had 7% growth if you exclude the coiled tubing business and of that 7% approximately half of that was driven by new units delivered to the field. During the quarter, well servicing utilization was 97% and the average rate per hour 592 this compares to first quarter utilization of 92% an average rate per hour of 581. As a percentage of the companies consolidated gross margin production services generated almost 53%, which was slightly higher than the prior quarters contribution.

Gross margin as a percent of revenue decreased to 41% compared to 44% in the prior quarter and 42% a year ago. Gross margin for the Production Services segment was $45 million, which was off about 4% from the first quarter. The decrease in Production Services margin and margin percentage in primarily due to reduced utilization of our fleet at coiled tubing units during the quarter.

Approximately 60% of our working Production Services assets are operating in areas targeting oil and 20% are targeting liquids-rich oil/gas plays. Also similar to last quarter our completion versus production split remains approximately 50/50 in production services.

Turning now to our expense trends for the company. G&A expense for the quarter was $22.3 million, which was up about 5% from the first quarter. The sequential increase was driven by increased third party consulting cost primarily to the rebranding and safety efforts in the company as well as some compensation-related expenses for additional head count. For the third quarter, we expect G&A to be flat compared to the prior quarter and we continue to expect full year G&A to be in the $86 million to $90 million range for 2012.

Depreciation and amortization expense was $40 million, which was up about 4% sequentially. This quarter-on-quarter increase reflects the impact of our fleet additions that were previously noted and we expect third quarter D&A to be in the $41 million to $42 million range.

Interest expense in the second quarter was $7.7 million, which was down about $1.9 million from the prior quarter. We capitalized approximately $3.9 million of interest expense in the second quarter, mostly related to our new-build drilling rig program.

For the third quarter we expect interest expense to be approximately $10 million, which reflects estimated capitalized interest of $2 million. For all of 2012, we expect total interest cost to be in the range of $46 million to $48 million, of which we expect to capitalize approximately $10 million. Looking into 2013 our capitalized interest cost will be significantly reduced, which will increase our interest expense next year starting in the first quarter.

Our effective tax rate for the second quarter was 38.2%, which was within the range of our normal statutory tax rate.

As of June 30 we had cash and cash equivalents of $20.4 million. We currently have $35 million borrowed on a revolving credit facility and $9 million in letters of credit, leaving current borrowing availability of $206 million. By year-end as additional rigs are delivered, we anticipate increasing the borrowings on our revolver to the $50 million to $70 million range and then start paying it down again in the first half of 2013.

Second quarter capital expenditures totaled $99 million, which included approximately $11 million for routine CapEx. We now anticipate our capital spending will be in the range of $325 million to $345 million for the full year 2012. The primary drivers for that are some additional facilities in South Texas and North Dakota and the additional six well service rigs that we ordered in the year are going to be, the last one should be delivered sometime in October, so we’re planning on paying for all of those in 2012 and some other timing considerations.

Our outlook for 2013 is to significantly reduce our CapEx number currently we’re targeting 2012 CapEx spending in the $120 million to $140 million range, which includes and estimated 2012 carry over spending in the $30 million to $40 million range as well as the estimated 2013 capital budget. The reduced CapEx spending next year is part of our plan to build cash that can be used for debt reduction.

And with that, I’ll turn it back over to Stacy.

Stacy Locke

Thank you, Lorne. Looking at the current market environment I think we would describe it as being a mild slow down. The softness in the market is weighing in a little bit on utilization and pricing and I think we’re seeing that in the land business and in the coil business and in the cased hole wireline in particular. In terms of pricing, I would say we’re probably averaging 5% or so down in those businesses. Well Services right now does not seem to be affected and in some cases as much as 10%. But I’d tell you the average effect on pricing is probably in that 5% range. So I would describe it as a pretty mild slowdown.

When you look at third quarter guidance for drilling, we do think the utilization will be down a little bit. We’ll guide 85% to 87% utilization. And due to the repricing of some of the existing rigs with slightly lower day rates, we think that we’ll probably average a little lower than second quarter average margins, somewhere in the $7,500 to $8,000 a day. It’s basically a balancing act between the high margin new-builds going into effect offset by the existing rig fleet average margins going down a little bit. So it’s a bit of tug-o-war, don’t know exactly, but we think directionally it’s probably a little down as opposed to up.

On the Production Services side, I think kind of the same balancing act. You’ve got probably cased hole wire being affected the most in terms of pricing. So that’ll have a downward weight on revenue and margin but we do believe that our coiled tubing business will be gradually improving in the third quarter and doing better in the fourth. So we’re going to guide revenues to flat for the second quarter to down to maybe 3%. And margins we think will be about on par at 41% of revenues in the third quarter as well.

So that ends our prepared comments and we’d be happy to entertain any questions. Thank you.

Question-and-Answer Session

Operator

Thank you, sir. We will now being the question-and-answer session. (Operator Instructions) We ask that you please limit yourself to one question and one follow-up question and requeue for additional questions. And our first question comes from the line of Brian Uhlmer with Global Hunter Securities. Please go ahead.

Brian Uhlmer – Global Hunter Securities

Hey, good morning, Stacy and Lorne. How are you all?

Stacy Locke

Good.

Lorne Phillips

Good. Fine.

Brian Uhlmer – Global Hunter Securities

Yeah, I just wanted to clarify a little bit on the cased hole wireline comments. And thanks for getting a little more detailed on how the revenues end up down, is that basin specific? Or just overall the entire market? Or can you quantify that a little bit? You said some areas 10%, but generally 5%. Is that across all markets in all segments?

Stacy Locke

On the case of total wireline, I would say that it’s closer to the 5% range. Joe, feel free to chime in if you – if I say something you think may be off a little bit. And I would say that it’s probably across-the-board. We do have a very big presence in the Bakken. As you’ve heard, a number of the operators there have reached out to the service sector for pricing concessions. Well that is an important market to us. A lot of those customers are big important customers to us, so we’re trying to work through that with them. And so I think clearly the pricing, you got to give a little on that and so that’s what we’re doing there.

Brian Uhlmer – Global Hunter Securities

Okay. And as looking at the percentage of revenues that contributes to get to down 3%, does that mean that the expectations are for well servicing utilization to come off a little bit? Or pricing to come off a little bit?

Stacy Locke

On well servicing, I would say well servicing looks to be flat to an upward bias. It just continues to form, perform very steadily. We’ve been on a track now for – gosh – over eight quarters of pricing just gradually coming up, just a slightward upward biased slope on pricing. We think that’s going to continue, but at worst case, get flat. Utilization is very strong. We still have – a lot of these units that we’re putting out are high-end well service units with taller mast that we’re doing a higher component of 24-hour work, which helps on pricing and margin, so that looks very good.

Brian Uhlmer – Global Hunter Securities

Okay. Sounds good. And to shift to my next question, over to the drilling side of the business, with your – with the rollovers that you have in 3Q, and also including one rig in the yard you said you’re bidding to West Texas, what makes you confident on getting the rig out to West Texas? And then what’s the composition of the rollovers in 3Q on a regional basis? And?

Stacy Locke

Well, I think they vary. West Texas rates so far have been flat to slightly up on renewals, maybe not up, the $1,000 to $1,500 a day that we thought six months ago, but maybe up slightly $500 a day, or something on that order. You go to the Eagle Ford, I think you’re down maybe $1,000 a day, something on that order, on average. In some cases maybe a little higher, in some cases flat. And I would say Bakken is flat to slightly down. Utah is solid. Marcellus, we already took that price decline of 5% to 8% a while back, and that hasn’t really changed. So, and everything else is just pretty stable. South Texas outside Eagle Ford is fairly stable. So it’s just modest decreases.

Brian Uhlmer – Global Hunter Securities

All right. Thank you, sir. I’ll turn it back.

Stacy Locke

Okay.

Operator

Our next question comes from the line of Jim Rollyson with Raymond James. Please go ahead.

James Rollyson – Raymond James

Good morning, Stacey and Lorne, everybody.

Stacy Locke

Good morning.

Lorne Phillips

Good morning.

James Rollyson – Raymond James

Stacey, in Colombia, can you maybe give us a little bit of color? You got this couple of rigs you’re working on, getting contracted, which I think you kind of been up and down on, on the timing and prospects for, but it sounds like you’re a little more up again. But maybe just how we should think about that and particularly the other six rigs, which I think, if I remember correctly renew at the end of the year, just kind of prospects for getting that all renewed.

Stacy Locke

I would say that we’re optimistic on that whole front down there. It – negotiations had kind of just gone stagnant there for a while and we’re back to negotiating again. We received pretty considerable interest in the two stacked rigs here in the last 30 days or so. So looks like pricing, as we talked about on the last call, we’ve got some pretty good pricing improvement down there, looks like on the bids for the two stacked rigs at that holding looks good. And so we’re, I would say, we’re optimistic again those two rigs will go back to work.

And then the six rigs that are currently under term are all working in the Castilla Field. We’re pretty confident those will all be renewed. We don’t yet have a sense whether, you know, I’d say the best case would be they renew at the current day rates, which is very attractive, or slightly down. But we do feel that they’re going to continue that drilling there. And we are one of the top performers for Ecopetrol down there. So we’re pretty confident that that’ll all continue on.

And I think the future in Colombia looks bright. There are more people that are looking at the horizontal aspect of the country, and we think that these rigs will fit that perfectly. They all have 500 in top drives, they all have walking systems, almost all of them have automatic catwalks so they’re in great shape to handle the horizontal drilling as that develops which, I think, we’ll see more of that in 2013 and increasing in 2014 and 2015. I think long-term it’s looking still good, as long as oil prices hold up, it looks good.

James Rollyson – Raymond James

Not expecting any gap between the current contracts on the six versus when they renew at this point?

Stacy Locke

Blaine sitting right here, he runs it. He’s saying no. We think that we’ll just continue on. We’ll just be working on getting these contracts renewed between now and the end of the year.

James Rollyson – Raymond James

Okay. Some of your peers have had a handful of rigs contracts getting bought out here in the last 60, 90 days or so. Have you guys been approached by anyone on that front? Or has it just been pretty much steady as she goes?

Stacy Locke

We only have – remember on the last quarterly call, we had two rigs that had been working for one of the big publicly traded companies that they were going to release and they released one of those that is still earning through October. The other one is stacked down there. That’s the one I mentioned. The other is earning through October. So that’s the only one that is a buy-out. They haven’t actually – they’re just continuing to pay it, but that’s the only one we’ve experienced that way.

James Rollyson – Raymond James

Okay. And Lorne, on CapEx you mentioned 120 to 140 next year. What’s maintenance when you get all the rest of the equipment delivered through this year? What’s a new maintenance level?

Lorne Phillips

Well, I think this year it’s in the 50 million to 60 million range. I think it would be biased upwards next year and it’s probably in the 55 million to 65 million range, would be my guess.

James Rollyson – Raymond James

Okay. Thanks, guys.

Stacy Locke

And Jim, just to follow-up on that question, for next year, that’s really what we’re focusing on is more maintenance CapEx and then carry-over from 2012 capital budget to be paid in 2013. So we’re not anticipating any unit growth in the businesses next year in order to be certain that we build cash and put a considerably amount of cash on the balance sheet by 12/31/2013. So we’ll be in a position by summer 2014 to pay a substantial part of that debt off.

Operator

And our next question comes from the line of Michael Cerasoli with Goldman Sachs. Please go ahead.

Michael Cerasoli – Goldman Sachs

Thanks. Good morning.

Stacy Locke

Morning.

Michael Cerasoli – Goldman Sachs

In trying to get a better idea of the well service rig market, at this point are you hesitant to add more capacity beyond your current growth plans? Or does the strong utilization on the debt signaling a room for higher spending as you look into 2013?

Stacy Locke

Well, that’s a good question. If we were not wanting to build cash next year and be in a position to pay a standard part of our debt down in 2014, we would be adding additional well service units. It’s a strong market. We could easily add more but it’s time for us to harvest some of the cash and be in a position to pay the debt. So it’s a strong market. We still think there’s demand out there. As soon as we pay that debt down, we’ll be – all things considered at that time, that if it’s like it is today, we would surely expect to go back and start building new rigs again.

Michael Cerasoli – Goldman Sachs

Okay. And then also in regards to the well service rigs, can you just talk a little bit about the cost side, particularly labor costs? You know how that market is trending from your perspective?

Stacy Locke

I think labor cost has been pretty flat. I mean we’re getting – when we look back over a number of quarters, it’s bouncing around a little bit but I would say that we are experiencing a little bit of margin expansion kind of on average quarter-over-quarter as you go forward. So probably seeing is adding a little bit to the margin line. But I’d say it’s been pretty stable there for a while now. Would you agree, Joe?

Lorne Phillips

Yes.

Stacy Locke

Yep.

Michael Cerasoli – Goldman Sachs

Okay. And then just my final question on coiled tubing. The units that are coming online later this year, are those contracted through year-end or is the calendar full for coiled tubing and it’s just a matter of pricing being weak? Or just some more details would be helpful. Thank you.

Stacy Locke

No. I’d say the trends are more away from term, more to spot although that’s been our experience. When we bought the business, we had three units on term. Today we have one. But we are in discussions pretty regularly with clients about putting other units on term. But the 2-inch units that are being delivered, they’re still on schedule in September, Joe?

Lorne Phillips

That’s right.

Stacy Locke

And hopefully be in the field in October. So those are not contracted but they’ll feed into some of our existing markets. And it’ll actually help us just like adding that fourth rig, fourth unit to the onshore market. We turned, on any given month, we’ll turn down a dozen or more jobs. It helps fill in the scheduling. And we’re having the same issue in coil. In a couple of markets we only have one coil unit where you really need to have at least two in a given market to adequately service your client’s need there. So it’ll just help make that business a little more efficient but they’re not under term at this point.

Michael Cerasoli – Goldman Sachs

Okay, that’s it for me. Thank you.

Stacy Locke

Thank you.

Operator

Our next question comes from the line of Josh Lingsch with Simmons & Company. Please go ahead.

Josh Lingsch – Simmons & Company

Thanks. Good morning.

Stacy Locke

Good morning.

Josh Lingsch – Simmons & Company

Question about the new well service rigs and the wireline units that you’re deploying. Do they go out at higher pricing than the existing units? And if so, can you try and quantify that?

Stacy Locke

I would say that they well servicing units that are coming out they’re a little bit of a new design. The ones we received most recently have been 112 foot mass and those are in high demand out there right now until they’ve gone right to work with good customers at I would say above average pricing. The next six that we have coming out are actually going up another four feet to 116 foot mass and we expect the same thing there. They’re very much they’re specific customers that are kind of waiting on those rigs to be deployed and they’ll go out at very favorable above average pricing.

On the cased hole wireline, I would say that pretty much all that we’ve added recently has been cased hole and I would say that we’ve add more to the markets where we’ve had the more favorable pricing so I would say on average those have gone out at a little above average pricing, but we’re also filling in on some markets where the pricing is continuing to improve. So, it’s kind of been across the board on cased hole wireline.

Josh Lingsch – Simmons & Company

Okay, that’s helpful. And, do you anticipate stacking in any of your older well service rigs now that these new ones are being deployed?

Stacy Locke

There aren’t any older.

Josh Lingsch – Simmons & Company

Or any that would be candidates, maybe not older is the right word, but any of the existing fleet.

Stacy Locke

No, you know, Josh, we’re somewhat unique in the well service space in that all of our rigs are either 550 to 600 horsepower units. So, by well servicing industry standards they’re all very new and young as a fleet so we don’t anticipate stacking any of them. They’re pretty much all out there working today. I guess some of our oldest units are maybe eight or nine years old and those we go through a refurbishment process on, but they have some life left on them.

At some point in the future we’ll build kind of a critical mass depending on the number of shale plays that have been developed and then conventional plays around the U.S., but then well probably slow our growth and basically cycle out our older units, but we’re two, three years away from that I’d say, at minimum.

Josh Lingsch – Simmons & Company

Okay. All right. Thank you. That’s helpful. I’ll turn it back.

Operator

Thank you. Our next question comes from the line of John Keller with Stephens. Please go ahead.

John Keller – Stephens

Hey. Good morning, guys.

Stacy Locke

Good morning.

John Keller – Stephens

Just a couple of quick ones here. You said you had mentioned that some of the coil units had rolled off-term and into the spot market. What’s sort of the order of magnitude on pricing that you’ve seen come off there? Or the decrement?

Stacy Locke

Well, the spot pricing is higher than the term pricing, first of all. So if you could keep the same utilization, we would be better off. The tough part has been – one of those terms was a unit up in the Marcellus and we had what we thought was an exceedingly soft market up there and we didn’t feel comfortable leaving the unit there when that term rolled off. So we’ve brought it south to Louisiana. And so there I would say the pricing across-the-board has softened a little bit. I’d say mildly 5%-ish range. It’s kind of hard to gauge that because it fluctuates. But I would say pricing is off a little bit. That’s it. In coal too. I mean it’s more – to effect, it’s all about utilization for us. We just need to get our utilization back up 65% to 75% and we’ll be in great shape.

John Keller – Stephens

Okay. Perfect. So utilization more so than pricing there.

Stacy Locke

Yeah, it’s all utilization.

John Keller – Stephens

Got it. And then this one might be a bit of a reach considering for the balance sheet limitations and obviously your desire to sort of harvest cash and pay down debt. But are you seeing anything in particular or anything intriguing in the acquisition market? And what might get you sort of off-the-fence and to move in that direction, if anything?

Lorne Phillips

I’ll take that, John. I mean really it’s just not that active for us. We look at things but given as – you put it well. Given our, as we see our balance sheet and our desire to harvest cash, we don’t see ourselves writing checks for an acquisition. And so we look at things because that’s the right thing to do. But it’s – we just don’t anticipate doing much in that market for the next few quarters for sure and maybe a little bit longer.

John Keller – Stephens

Perfect. Well, appreciate it. That’s it for me, guys.

Stacy Locke

Okay.

Operator

(Operator Instructions) And our next question comes from the line of Mike Urban with Deutsche Bank. Please go ahead.

Mike Urban – Deutsche Bank

Thanks. Good morning, guys.

Stacy Locke

Good morning.

Mike Urban – Deutsche Bank

Wanted to follow up on some of the questions on the Production Services side. Obviously you’ve talked about cutting back your CapEx quite a bit and not taking any deliveries beyond the current program. But have you considered holding off on deploying some of the units that are in the pipeline? Or given the softness in some of those markets? Or did the returns in margins still make sense at this level to put those out in the field?

Stacy Locke

Well, when you break it down, we really only have nine units left to deploy. We’ve got six well servicing units and those are all 116 foot mass units and the demand is out there waiting for those. So we want to get those out as quickly as we can because they’ll go right to work at very, very strong average hourly rates. And the last remaining cased hole wireline units, there are only three left, and we’ve broken into a couple of new markets that we think offer some real opportunity, one in particular like the Permian, and we need those units to kind of fill out a nice complement for a district office.

So we definitely will take those and if we weren’t – as I mentioned earlier, if we weren’t at a period in our life cycle where we wanted to harvest the cash, we would grow wireline as well as Well Service and we’d grow coil a little more as well. But it’s our time to harvest this cash and we’re going to do that and get that debt level down to a level we’re comfortable with and then we’ll be right back on the growth track.

Mike Urban – Deutsche Bank

And just philosophically, I mean how do you think about deploying those assets? Again, if you were still in growth mode and allocating capital to those businesses, if you were to see the markets deteriorate further here. What’s your criteria for either not deploying that asset or taking an existing asset and pulling it in? Do you do that once you go below cost of capital? Do you do that down to cash breakeven? How do you typically think about that?

Stacy Locke

Well, that’s – so you’re talking about a market that’s probably different than what we’re experiencing now. You’re talking about a market where it deteriorates further and, yes, we do – all of these decisions are return based. Our drilling rigs, we look at a 20% internal rate of return hurdle rate and I’d say generally across the business lines that would be a pretty good floor. Wouldn’t you say, Lorne?

Lorne Phillips

Yeah.

Stacy Locke

I think our Well Service returns, wireline, coil are in excess of 20%. But I’d say that’s a good floor number for us to use.

Mike Urban – Deutsche Bank

Okay. That’s helpful. Yeah. Wasn’t suggesting that’s where the markets were, just if you did see things that could turn for the worse. Just trying to get a sense for how you would think about that process.

Stacy Locke

Right. Well, we definitely would reduce CapEx to zero if we needed to if the returns were not there. It’s all return-based decision making.

Mike Urban – Deutsche Bank

Sure. And then one last question and maybe reading too much into this. But the name change certainly reflects the nature of your business and where you’re earning revenue and margin today. Does it also reflect a philosophical shift? So once you do return to an investment profile would the emphasis be more on the production services side and just the service side in general? Or do you still see a balanced approach to the business going forward?

Stacy Locke

Definitely a balanced approach. We think the – I’d say we’re in the four key core businesses, Drilling, Well, Wire and Coil. And Fishing & Rentals is still there. It’s not a growth area for us. It’s a good solid business, but the four core businesses are the ones that we want to be in and we want to grow all of them. We think they go extremely well together in terms of providing a broader array of services to our clients, and we think the cross-selling opportunities are tremendous there. We have already witnessed it time and time again.

So we would want to continue to grow – it doesn’t have to be 50% Drilling segment versus Production Service segment. It’s just where the best return investment opportunities are, but we created a pretty sizable engineering department over the last few years and we’re putting out first-rate drilling rigs, I think some of the best drilling rigs that are hitting the market, and they’ve come out of the box just performing superbly. So we definitely plan to continue building new rigs and growing all these businesses together.

Mike Urban – Deutsche Bank

Great. That’s all for me. Thank you.

Stacy Locke

Okay. Thank you.

Operator

And your next question comes from the line of Daniel Burke with Johnson Rice. Please go ahead.

Daniel Burke – Johnson Rice

Hey, guys. Thanks for squeezing me in. I just had two pretty specific ones left. Was curious on the work-over side. The sequential improvement in hourly rate I think maybe Lorne had mentioned 24-hour work. I was wondering how substantially did 24-hour work tick-up from Q1 to Q2? And was that really the primary driver of the improved sequential hourly rate?

Lorne Phillips

Well, I think the primary driver in the improved rate is that the rigs were putting out or going to work. That team is doing extraordinary job. That stuff’s going to work immediately as soon as it’s prepped, and it’s going in at very high rates out on the field. I think that’s the primary driver. I think our 24-hour work has edged up. It – every quarter, it seems to be edging up a little bit and probably related somewhat to increased pad drilling, but it’s a good business. We like the 24-hour work and we continue to pursue it, but I think the biggest driver is just these rigs are going in at some of the best rates. As Stacy mentioned, we’re trying to place them in the best markets that we can and that allows us to do that. And there is some legacy price increases in the market. It’s very, very moderate.

Daniel Burke – Johnson Rice

Got it. And then Lorne, appreciate the detail on the timing of the fleet renewals on the drilling side, can you refresh my memory, the second half of this year, how many rigs do you have to renew in West Texas? I know those contracts have had decennteration for you all.

Lorne Phillips

Yeah, I think it’s probably – I was looking before the call – I think we’ve probably got two to three in the third quarter and in the fourth quarter, I think it’s probably five perhaps of the 12? Five or Six, I mean, Don, do you...

Don Lacombe

I concur with that.

Lorne Phillips

Okay.

Daniel Burke – Johnson Rice

Okay. Well great, guys. That’s all I really had left. Thanks for the time.

Lorne Phillips

Thank you.

Operator

And our next question is from the line of Jeff Geygan with Milwaukee Wealth Management. Please go ahead.

Jeff Geygan – Milwaukee Wealth Management

Morning. Thanks for taking my call. Stacy, you’ve talked about harvesting cash, paying down debt, strengthening your balance sheet going forward, which I would be in favor of, at the same time you’ve indicated your CapEx plans for 2013 are $120 million to $140 million, less $55 million to $65 million maintenance, which tells me you still have $60 million to $80 million in new build, is that right? And if so, can you tell me what you’re expecting to build next year?

Lorne Phillips

Jeff, I’ll handle that. It’s – you’re correct that the routine is in that $55 million to $60 million, $65 million range. The $120 million to $140 million also would include $30 million to $40 million estimated carryover from this year, of that I think probably $30 million, close to $30 million would be new builds and there’ll be some, it could be very small, could be up to $10 million, let’s say, of other, whether it’s routine or just other expenditures in this year that rollover that are paid for in 2013. So when you narrow it down, $120 million to $140 million, take the $30 million to $40 million range off for the carryover, that leaves $90 million to $100 million in capital budget for next year.

And as you look at that 55 to 65 routine, the delta would be various other items, not new builds, but we may decide we want to replace mud pump or needing an additional top drive to make sure we can service our customers in the field appropriately, things like that. But we are still sorting through that and we’ll finalize it, we’ll have more detail on it in our next call.

Stacy Locke

But just to be clear, we don’t plan to be building any new units in drilling or any of the production service lines in 2013. It’ll only be the new build carryovers from 2012 capital budget on the drilling side for the most part.

Jeff Geygan – Milwaukee Wealth Management

Great. Thanks for clarifying that.

Stacy Locke

You bet.

Operator

And ladies and gentlemen, that does conclude today’s question-and-answer session. I would like to turn the call back to management for any closing remarks.

Stacy Locke

Okay. Well, that should wrap it up. We appreciate you all participating on the second quarter call, and we look forward to visiting on the third quarter call. Thank you very much.

Operator

Ladies and gentlemen, this does conclude today’s conference call. You may now disconnect.

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