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Pioneer Energy Services Corp. (NYSE:PES)

Q3 2012 Results Earnings Call

November 1, 2012 11:00 AM ET

Executives

Anne Pearson - DRG&L Investor Relations

Stacy Locke - Chief Executive Officer

Lorne Phillips - Chief Financial Officer

Red West - President, Drilling Services Segment

Joe Eustace - President, Production Services Segment

Analysts

Jim Rollyson - Raymond James

John Keller - Stephens Inc.

Blake Hancock - Howard Weil

Josh Lingsch - Simmons & Company

Operator

Ladies and gentlemen, thank you for standing by. Welcome to the Pioneer Energy Services Third Quarter 2012 Earnings Conference Call. During today’s presentation, all parties would be in a listen-only mode. Following the presentation, the conference will be open for questions. (Operator Instructions)

This conference is being recorded today, Thursday, the 1st of November, 2012. I would now like to turn the conference over to Anne Pearson of DRG&L Investor Relations. Please go ahead.

Anne Pearson

Thank you, Luke, and good morning to everyone. Before I turn the call over to Pioneer’s CEO, Stacy Locke; and to 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 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.

As a reminder, information reported on this call speaks only of today October 1, 2012, so any time sensitive information may no longer be accurate at the time of a replay.

Management may -- make -- will make forward-looking statements today that are based on beliefs and assumptions and information currently available to them. While they believe the expectations in these statements are reasonable, they can give no assurance they will prove to be correct.

They are subject to certain risks and uncertainties that are described in this morning’s news release and also in recent public filings with the SEC. If one or more of these risks should prove to be incorrect, actual results may differ materially.

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

Now, I’d like to turn the call over to Stacy Locke, Pioneer CEO and President. Stacy?

Stacy Locke

Thank you, Anne, and good morning, everybody. Joining me here in San Antonio is Red West, President of our Drilling Services Segment; and Joe Eustace, President of our Production Services Segment; and Lorne Phillips, our Chief Financial Officer.

When you look at our third quarter results, there were kind of three areas that led to the quarterly kind of under performance of what we expected and those three areas where U.S. land drilling, wirelines and coiled tubing services.

When you look at the U.S. land drilling sector, there were three primary factors that contributed to the softness there. One is that day rates adjusted downward closer to the 10% level for a number of these rigs and the 5% to 10% range that we had kind of anticipated at the second quarter call.

Also kind of in association with our, actually good utilization of 86% for the quarter, there was a lot more noise behind that number. In other words, we had to struggle a little harder to keep that good utilization up and as a result, we had occasional rigs that would go down and stack and incur stacking costs. We would keep the labor, knowing that we were going to go back to work and we were able to go back to work in most cases.

And then we had a couple of pretty good moves from one region to another embedded in there and those additional costs affect your margin. And we just had a little more of that than we anticipated. But I was very pleased frankly with the outcome of our utilization.

In addition, the newbuilds, we delivered very steadily here and I think that we experienced what we’ve always experience, really with these newbuilds and that is the initial startup months or kind of one time costs at the outset.

It usually affects your general costs for two to three months and then you kind of get back on track. And I just don’t think we really factored that in as we were looking at our guidance. We are just excited to get these newbuilds out and running. So that is really kind of what was behind U.S. land drilling.

If you look at wireline, there was number of factors there that influenced our wireline business. It was considerably softer than we had anticipated. There, again, industry-wide utilization was off a little and that just causes greater competition for the work, which then affects pricing kind of light drilling. And those adjustments were closer to 10% as well rather than the 5% to 10% we were anticipating.

Another aspect of the wireline business was during this quarter there was a shift in the mix a bit. There was a little less of the high margin, big ticket plug and perf work related to the long lateral horizontal activity and a little bit more towards the routine, and so you lose some profitability there as a result of that.

In addition, we -- related to that I guess, is some of the customers that are client of ours that have been good long standing clients have moved a little bit more towards sliding sleeve activity for their completions as opposed to the plug and perf. And that, therefore, causes us to go out and find clients to replace those and we are doing that. And we don’t feel like it’s a tidal wave of change, but we do need to replace those clients.

And some of the clients that have shifted more to sliding sleeve have been significant to us. So it’s just a matter of getting out, finding new work and we’re doing that and but it did affect us in the quarter.

Open hole logging, which has been historically a very high margin business for us, has -- was also off this quarter due to increased competition and due to more horizontal drilling activity in some of the markets where we do a lot of open hole logging, because a lot of the horizontal work doesn’t require a log on every hole. So that just affects the amount of work there is to be done.

And then, lastly, Hurricane Isaac did have an impact on our wireline units in South Louisiana, both onshore and our skid units for offshore for deepwater and shelf work. So that was kind of a mixture of activity there that affected wireline during this quarter.

And then lastly, coil, there were probably lots of little issues related to coil, but the big one was Hurricane Isaac. It basically shutdown our very profitable offshore coil market, which is both shelf and deepwater that was shutdown before, during and after the storm. And it also affected our onshore South Louisiana work there. So that was the real killer there for coil.

Now, drilling down a little bit into more detail on the drilling segment, U.S. land drilling segment or drilling segment overall. As I mentioned earlier, our utilization remains strong at 85% and we do have a number of bright spots, I think, in the drilling business.

Excuse me, we’ve had exceptional performance with our newbuild rig designs and are receiving attention kind of across the country from numerous operators that have not used Pioneer in the past and it’s creating, frankly, opportunities for some of our existing rigs.

As an example, we recently at the request of a client put a 7500 psi fluid system on one of our 2001 vintage newbuilds. And that client on its second well drilled that client’s record well.

So you may recall that all of our 1500 horsepower rigs which is really unique to Pioneer on all our newbuilds, there are 2000 horsepower mud pumps with 7500 psi fluid ends and that has really -- had proven to be effective in the marketplace out there and customers, I mean our clients are appreciating it and other potential clients are taking notice of it. And this is just an example of one that took notice of it, had us put it on and it is performing well above their expectations.

In addition to that, I think our walking system has been very well received on these newbuilds and its creating opportunity for us to install similar type walking systems on some of our existing rigs for pad drilling, this would be existing SCR rigs.

Because at the end of the day when you look at all of the inventory of available SCR and AC joystick rigs out there, there is a very large number of them that don’t walk. They skid, but skid has a lot of characteristics that clients -- many of our clients don’t want.

And so this is just a real, a great opportunity, because of style rigs that we have, the 50 series, in particular can all take and actually, frankly, all of our mechanical rigs. We have one mechanical rig, box-on-box with a walking system that’s been on there for five years and is absolutely a top performing rig for one of our large clients.

But anyway these rigs adapt very well to the pedestal style walking system and we are getting in a number of conversations about putting those on existing rigs, and putting them onto pad drilling programs. So we’re excited about that.

In Colombia, you may recall from prior conversations that we’ve had two of our eight rigs stacked for the better part of the year. I’m finally pleased to announce that the newly upgraded rig to the 1500 horsepower from the thousand is now under contract and it should begin operations at very attractive terms and conditions here this -- in the first part of this month. So we are excited to get that rig back to work.

And the other stacked rig, the 1000 horsepower also looks very, very promising. We are in kind of final negotiations with a publicly traded company to put that rig back to work and so we don’t have it done yet, but we are optimistic that will go back to work prior to the end of this year. So that is looking up. Once those two get back to work, we will be back to 100% utilization there in Colombia.

On the Production Service side, overall, revenues were down 6%, more importantly, EBITDA was down 17%. There again, the big hit was wireline, as we previously talked about, which is the largest division of the Production Servicing group.

And in that case, revenue for wireline was actually down 11% and EBITDA was down 24%. So it was a rough wireline quarter but we’re optimistic that some of that stuff we can correct and move on, and we think the market is still good there.

Well service and revenues were actually up a little bit. Utilization was down slightly, from 97% down to 91%, still industry leading utilization and the hourly rate that we charge was up to a new all time high $606 per hour, which is the highest hourly rate. First time, we’ve broken $600 since 2008 and that’s up from $592.

In coil tubing, as we’ve already talked about, revenue was down 3% and EBITDA was just hammered for coil. And fishing and rental was down 6%, and EBITDA was off there as well. But anyway that’s kind of a rundown of what’s going on in the businesses.

I’m going to turn it over to Lorne and we’ll go through some of these financials, and then I’ll return for some final comments regarding the outlook. Lorne?

Lorne Phillips

Thanks, Stacy. So this morning we reported third quarter consolidated revenues of $229.8 million, which was flat versus the prior quarter. Our net income was $2.6 million or $0.04 per diluted share, which compares to net income in the second quarter of $9.7 million or $0.15 per diluted share, and our adjusted EBITDA was $55.6 million in the quarter, down 12%, sequentially.

Looking now at Drilling Services, the revenue for Drilling Services totaled $125.7 million, an increase of 6%. The majority of the increase in the revenues was due to the rollout of five of our new-build rigs since early June.

Our operations in Colombia also contributed to the growth. They accounted for $24.4 million of the Drilling Services revenue total. And, for Colombia that’s up 9% from the prior quarter. As mentioned by Stacy, one of the two idle rigs will go back to work with Ecopetrol next week.

Turnkey revenue in the quarter was $1.9 million, an increase of $1.5 million from the prior quarter. Our average drilling margin per day was $7,187, which was $845 lower, sequentially, and, that decrease in margin per day reflects mobilization costs of approximately $800,000 related to moving rigs to higher-demand regions.

Higher startup costs for our five new-build rigs that began operating during the third quarter and the impact of some renewals at moderately lower pricing. 58 of our drilling rigs are currently working. 46 of these rigs are under term contracts that range from six months to four years.

Of the 40 rigs that are on term contracts in the U.S., eight are up for renewal in the fourth quarter of this year, 11 in the first quarter of 2013, 10 in the second quarter of 2013, four in the third quarter of 2013, with seven expiring beyond that point. The average remaining term is nine months for drilling contracts in the U.S. If you exclude the recent new builds, our average U.S. term length is five months.

In Colombia, six of our eight drilling rigs are working on a contract that expires on December 31, 2012. And as mentioned earlier, we have one other rig about to commence operations. And, currently, approximately 90% of our working rigs are drilling wells targeting oil.

Turning now to Production Services, Stacy covered the majority of the breakdown by business. Hurricane Isaac had about a $2 million revenue impact on the business as a whole.

The gross margin for the segment was $38.7 million, which was down about 14%, sequentially. And, our margin as a percentage of revenue decreased for the reasons Stacy outlined to 37%, down from 41% in the prior quarter.

As a percentage of the company’s total revenue and total gross margin, Production Services generated approximately 45%, and 51%, respectively, for the quarter. And, approximately 60% of our Production Service assets are operating in areas targeting oil and approximately 20% are targeting liquid rich plays.

Turning now to expense trends for the company, our interest expense was $9.5 million, which was up about $1.8 million quarter-over-quarter. This reflects, primarily, reduction in capitalized interest.

Last quarter, excuse me, this quarter, we capitalized $2.4 million of interest expense, again, primarily related to our new build drilling rig program. For the fourth quarter, we expect interest expense to be approximately $11 million, and we expect to capitalize an additional $1 million.

We expect our capitalized interest to be significantly lower in 2013 due to the completion of the new build program in the first quarter, and as a result, our interest expense will increase in 2013 as amounts that have been capitalized are now included as expense on the income statement.

G&A expense for the third quarter was $21.3 million, which was down about $1 million quarter-over-quarter, driven primarily by a decrease in incentive related compensation. For the fourth quarter, we expect G&A to be in the $21 million to $22 million range.

Depreciation and amortization expense was $42 million, which is up about 5% and reflects the impact of our ongoing fleet additions. We expect fourth quarter D&A to be in the $43 million to $45 million range.

Our effective tax rate last quarter was 35.8% versus 38.2% in the second quarter. In the fourth quarter, we expect the rate to be 38% to 40% before the impact of any currency gains or losses.

Looking now to our balance sheet, we had cash and cash equivalents at September 30th of $6.3 million. At the end of the quarter, we had $80 million drawn on our revolving credit facility and $9 million in letters of credit, leaving borrowing availability of $161 million. Since the end of the third quarter, we have drawn down an additional $20 million on the revolver.

The balance on our revolver is higher than our previous forecast driven primarily by lower-than-expected earnings for the second half of this year. We currently do not expect to borrow additional funds in our revolver but that is dependent on timing of our collections and CapEx payment.

Following the delivery of the new build drilling rigs in the first quarter, we intend to begin paying the revolver down. Third quarter capital expenditures totaled $97 million.

We now expect our capital spending will be in the range of $335 million to $355 million for the full year of 2012. And for 2013, our CapEx spending target remains in the $120 million to $140 million range, which includes estimated carryover spending of $30 million to $40 million from 2012.

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

Stacy Locke

Okay, Lorne. Thank you. Looking to the future a little bit, I think we feel that the -- talking about the land drilling side, we feel like the rate adjustments are pretty much a known quantity at this point. However, we’re going to guide lower because we have to cycle through those decreased rates as we renew term contracts going forward.

And, I think when you look at the number of term that are up for renewal in the fourth and the first quarter, I think it sums up to about 19 in total. We do anticipate that at least three quarters of those or two thirds or more will be renewed.

We’re not anticipating a bunch of contracts being dropped there. But those will adjust in some cases to lower rates. And when you look at the classes of rigs, the two classes of our rigs that have had the biggest hits or rate adjustments have been the SCR AC class rigs and the mechanical rigs with top drives.

Those rate adjustments are probably on the order of magnitude of the 10% range whereas our lower horsepower mobile fleet, like the cabin 700s, 900s, and our 1000 to 1300 mechanical fleet, which is mostly in west Texas, those rates are holding pretty firm. And if they’re adjusting at all, it’s much less in the order of 0% to 5%.

So, we kind of feel like that is where the rates are going to be for a while. We think we are there on rates. We just need to cycle those changes through the rest of the fleet as we renew contracts.

And, the rigs are all performing very well and the utilization is high. So, we think the bad news is out there. We just need to cycle it through the rest of the rigs. And then continue delivering our new builds, which will pull those average margins up a little bit over time.

So, our forward guidance is 83% to 85%. So we are guiding a little bit less of the utilization in the fourth quarter. And we think our average margins aren’t going to be too different from where we were in this quarter, somewhere ranging between $7,000 and $7,300 and so that is our land drilling outlook. When you look at the Production Services business, I think the same applies there.

I think a lot of the rate moves have been made. And there is a softness there in the market but, it’s still very, very active. And, I think, in our case, there are a number of situational factors that can be overcome like Hurricane Isaac, like customers that choose sliding sleeve over plug-and-perf. We can replace those. There are plenty of clients out there.

So we think that we can make those changes and keep that back on track. But we will guide lower for the fourth quarter. Part of that is just your typical seasonality, Thanksgiving, Christmas, shorter days, et cetera. So we will guide revenues down 5% to 10% and we’re hoping to hold margins about at that 37% of revenue level or maybe slightly lower on the order of 1%, maybe 2%. It’s just hard to gauge.

So I’d say generally speaking, we just feel like the bad news is out there on pricing. That, if oil prices stay firm that the capital budgets will more than likely be worst case, kind of flat to $12 million but more likely up in 2013 and sitting behind all of that are these creeping natural gas prices, which is nothing but positive for the industry.

And, of course, we have a looming election out there, and if we find ourselves with an administration that is truly pro-energy, I think we will see some real help there. So we have some optimism. But I’d like to conclude the prepared remarks and happy to entertain these questions. Thank you.

Questions and Answers Session

Operator

(Operator Instructions) Our first question comes from Jim Rollyson with Raymond James. Please go ahead.

Jim Rollyson - Raymond James

Good morning, guys.

Stacy Locke

Good morning, Jim.

Jim Rollyson - Raymond James

Good color so far. Stacy, you talked about the Columbia six rigs that contract ends at the end of the year. The only thing I didn’t hear you talk about them in Colombia, is just kind of the prospects for getting those renewed and how that’s going?

Stacy Locke

Well, there all six of those rigs have been working in the same field there. Southeast of Bogotá, in a field called Castilla, there the top-performing rigs in that field, we have not begun negotiations on the renewal of those contracts, but it’s our expectation that those rigs will be renewed either on a permanent or an interim basis while we renegotiate two longer-term contracts.

But, those discussions haven’t started taking place. We’ve been focused on some of the -- well, like this other rig that is now going back to work. That we have kind of focused on that negotiation with Ecopetrol. And, now, we’ve got that done.

So, I expect here soon we will begin those discussions with Ecopetrol. But we fully expect those six rigs to stay right there working in Castilla field.

Jim Rollyson - Raymond James

Okay. And, as I guess, as a follow-up on the well-servicing side, good job getting above $600 an hour for rates. Can -- it’s the one market you didn’t really detail a whole lot as far as the outlook. Obviously, you will get the seasonal aspects of it but my sense is that market is holding up better. Can you maybe talk about pricing and how you think about that over the next two or three quarters?

Stacy Locke

Well, that well-servicing market for us has just been stellar. We’re putting out a rig that’s -- our latest rig where we’re at 103 well-service units right now. We have three more of the 116-foot map rigs yet to be delivered. Those are already called for in certain markets.

So those -- and before that, we put out the 112-foot master rigs, the prior six. So, all of those have been very, kind of, fit-for-purpose for clients that need the taller mast-type units. So, that’s worked very well. But overall, the group’s doing fine.

I think there is some softness in the market. But it hasn’t really impacted us yet. I think we would be naive to think that it will never impact us if it stays this way. But so far, we really haven’t felt it.

Our utilization continues to be good. We still have a number of 24-hour jobs going. I think, I looked yesterday we had seven and 24-hour units working. So the market still looks strong. I think if you shaded it in any way, I think you would shade it a little softer than prior like the other businesses we’re seeing. But I don’t think it will have a big impact on us.

Jim Rollyson - Raymond James

Okay. Thanks.

Stacy Locke

You bet.

Operator

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

John Keller - Stephens Inc.

Good morning, guys. I just wanted to get your thoughts on how 2013 plays out. I think you have always had a pretty good take on the macro here. With operators for spending through budgets in this exaggerated holiday period. But I think there is a sort of growing sentiment that 2013 is going to snap back pretty quick.

And if that’s the case, then presumably you are starting to have discussions, soon if not already about kind of land rigs going back to work. I just like to get your thoughts on that?

Stacy Locke

Well, it’s hard to say, there’s a -- frankly, I’ve been a little surprised how soft the third and fourth quarter has gotten with oil prices having come down fairly precipitously, but then bounce right back and one rationale would be that operators pre-spent their budgets.

The other is getting greater efficiencies out of the equipment they are running. And probably those are both true. But something else has happened, this big positive with operators and that is that with stacked rigs prices come down and they love that. So, I think they’re going to want to enjoy that for a while longer.

I think that you are probably going to see a fairly soft fourth quarter and first quarter. And then there will come a point in the year, which I would anticipate would be kind of in the third -- second certainly the third at the latest quarter, where if we’re correct and commodity prices hold up that -- and kind of back there, if we get any of these natural gas price improvements due to these winter periods that gives someone a chance to kind of lock in some pretty good natural gas pricing, which could really help.

But, we don’t know whether that will happen or not. But if the budgets, they get back to work, budgets are up, which I think they will be then I think you are right. Activity is going to pick up. I think it’s going to be a softer start to the New Year, because it just seems it always work that way. They’re enjoying the cost savings.

But there will come a point where they will start absorbing the equipment that’s available out there. And then I think we will be full running certainly by the third and fourth quarter of next year. And I would anticipate, if something derail on oil prices that you will have a very strong ‘14, would be my guess.

John Keller - Stephens Inc.

Great. I appreciate that color. And then I’d also like to get you just to elaborate maybe a little bit on what you’re seeing out in the Permian. I think now its -- at least in terms of rig count, it is your largest market. And maybe you could also put in context kind of what you’re term coverage is out there and contract roles.

Stacy Locke

Okay. Good question. Well, we have -- I guess we have 18 in the Permian and three in the Panhandle is that right, Red, is that right, Joe? Four in the Panhandle, okay. 17 in the Permian, four in the Panhandle. The 17 are all 100% utilized and I think 100% under term right now.

John Keller - Stephens Inc.

Okay.

Stacy Locke

So, they’re pretty much all termed-up. We anticipate that we will be able to renew the Permian term. We have a little less certainty I think up in the Panhandle area. But where there’s quite a bit of activity in and around the Panhandle, even including the Mississippian, the Hogshooter, the Granite Wash. So we think that we will be able to reposition rigs there but that is where we have a little bit of weakness in that kind of broader West Texas market.

But I think the -- I believe that the vertical market -- you really have two different markets out there. You’ve got the vertical market and the horizontal market and our mechanical rigs with top drives are drilling in the horizontal plays and our mechanical rigs without top drives are drilling in the vertical plays.

We are drilling for all big, healthy, publicly traded companies for the most part. And as far as we can tell, there’s going to be a continuation there. So, we’re very optimistic. And I think the day rates are already kind of established would be my best guess on that.

John Keller - Stephens Inc.

Perfect. I appreciate it, Stacy. Thanks.

Stacy Locke

You bet.

Operator

Thank you. A next question comes from the line of Blake Hancock with Howard Weil. Please go ahead.

Blake Hancock - Howard Weil

Good morning, guys.

Stacy Locke

Good morning.

Lorne Phillips

Good morning.

Blake Hancock - Howard Weil

Stacy, in the past, you’ve talked about your mechanical rigs with top drives demanding much higher day rates than your mechanicals without the top drives. What kind of convergence are we seeing there between the two now as this rig counts soften. I know you said the ones with top drives were down 10%. What’s the variance between those two as far as day rates go now?

Stacy Locke

Well, that’s a great question and a good observation. Those mechanical rigs with top drives for us were anomalous before. They were abnormally priced, I would say. The average day rate on the mechanical rigs with top drives previously was about $21,500. With the 10% adjustment, they are now kind of back into a norm in their relationship to the mechanical rigs without top drives.

I think the general rule of thumb in the industry has been that a top drive adds about $3,000 or so a day in day rates. And so, if you take our fleet of mechanical rigs in West Texas that are kind of in that just say $15,500 to $17,000 a day rate. The new top drive mechanical fleet would be about $3,000 on top of that.

Blake Hancock - Howard Weil

Okay.

Stacy Locke

So we are cut it back in parity really.

Blake Hancock - Howard Weil

Okay. Great. That’s perfect. And then I guess one follow-up on that. You guys have about 23 mechanical rigs without the top drives.

Stacy Locke

Correct.

Blake Hancock - Howard Weil

Probably about half of them could be considered for upgrade. Given the current outlook, is there any possibilities that you guys would add top drives to these to continue to high grade that side of the fleet or is that something you would sit on and will that be more customer driven or would you guys proactively do that?

Stacy Locke

Well, we have upgraded pretty much all of those as we made the move from stack conditions in East Texas and North Texas and certain other markets to West Texas. They went through a very significant upgrade. So, most of those mechanical rigs already have -- some of them brand new drawworks, a lot of -- most of them have rounded bottom mud tanks.

Almost all of them, if not all of them have iron roughnecks on them. They got big mud pump packages. So, they are already in blue chip condition for mechanical rigs. I think I would proudly say, I think it’s as competitive of a mechanical fleet as we’ve got. And most importantly, we deliver it with very good safety and downtime results.

So, those rigs are kind of where we want them. 10 of them have top drives and those are sprinkled in a variety of markets actually. We’ve got two of them in the Bakken. We have one in the Uintah Basin. I think we have four in -- four or five in West Texas. We’ve got one in South Texas. And any way I maybe probably missing a couple in there and that one in the Marcellus.

So, they are spread about, but they perform very well. You’ve heard me mention of the past, we’ve got one up in the Uintah Basin that’s been drilling for one of the big publicly traded companies. And it has been their top performing rig year-after-year and all they have running is our one walking 1,000 horsepower mechanical rig with a top drive and AC electric rigs, state-of-the-art and we continue to outperform that whole batch of rigs out there on a year in, year out basis.

So, they do perform very, very well. Not all clients are going to want to work mechanical rigs with top drives. They are going to be some that just flat out prefer to have an AC joystick rig. But there -- we hopefully -- over time that fleet will probably gravitate more towards the Oklahoma, West Texas market where they’re -- they’ve been using mechanical rigs longer. But for now, we got them busy and doing very well.

Blake Hancock - Howard Weil

All right. That’s great. And if I could sneak in one more.

Stacy Locke

Sure.

Blake Hancock - Howard Weil

Just in terms of the economics in the U.S., would it be more compelling for you guys, if you can get the one stacked rig in Colombia under contract? Would it be compelling for you guys to maybe send another rig or two down there?

Stacy Locke

We always explore that. We really feel so positive about the U.S. market and even with the little softness that we’ve experienced here, there are going to be some great opportunities in the U.S. in the shale plays and in new shale plays that are developing.

And we see a lot of opportunity here for additional new builds down the road. Now, it’s not in our cards in the short-term, because we’re trying to build cash, reduce indebtedness. But once we get out, kind of late ‘14, ‘15, we just feel like this U.S. market is just bar none the best in the world. And so, we will probably allocate our capital here in the U.S.

Blake Hancock - Howard Weil

That’s great. I’ll turn it over. I appreciate it, you guys.

Stacy Locke

You bet.

Operator

(Operator Instructions) A next question comes from the line of Josh Lingsch with Simmons & Company. Please go ahead.

Josh Lingsch - Simmons & Company

Good morning, gentlemen.

Stacy Locke

Good morning.

Josh Lingsch - Simmons & Company

Turning back to Columbia for a second and maybe more from a macro view environmental permitting has caused the rig count in the country to come down pretty sharply this year, not that it has necessarily had the same effect on your rig count in the country. But considering you probably have a better insight than most, could you give us an update on the market with respect to permitting?

Stacy Locke

Well, I can’t give you a lot of in-depth, other than you are correct that the environmental permitting has fallen way behind and has slowed up activity there. And I don’t really understand why and but I’m sure, that they’re desiring to collect that is all I can say.

They’ve been better in the past. And I don’t know exactly what’s caused the issue there. But it is affecting the market. I’m sure it will get better. I just don’t know enough beyond that to tell you.

Josh Lingsch - Simmons & Company

Okay. Fair enough. Thanks. And then turning back to the U.S., the 19 or so rigs that are rolling off contract this quarter and next. As you are renegotiating these, how many do you view as candidates to move out of their current locations in order to keep utilization high, if any?

Stacy Locke

I would say that there will be a few of them in that group -- not I mean the vast majority will stay right where they are. But we’ve got some opportunities that we’re already discussing, just an example, one of the mechanical rigs with the top drive out in the Bakken. We are already having discussions with moving that rig into a different market with the same operator. And there will be some cases like that. We don’t -- it will be small relative to the group of 19, though.

Josh Lingsch - Simmons & Company

Okay. Okay. And then maybe one more as a follow-up and you touched on this earlier. But with regards to your Q4 guidance on cash margins and so at the midpoint it’s fairly flat quarter-over-quarter. And I’m just making sure I understand this right, it’s cost will likely come down a bit with less startup costs related to the new builds. And then maybe a little bit further pricing declines that evens out and that’s what yields the Q4 cash margins flat quarter-over-quarter?

Stacy Locke

Yeah.

Josh Lingsch - Simmons & Company

Okay.

Stacy Locke

Basically, right on the money.

Josh Lingsch - Simmons & Company

Okay. Thank you, Stacy.

Stacy Locke

Okay. Thank you.

Operator

And then, I would like to turn the conference back to you for closing remarks.

Stacy Locke

Okay. Well, that concludes our third quarter call and we appreciate everybody participating today. Thank you.

Operator

Ladies and gentlemen, this concludes the Pioneer Energy Services third quarter 2012 earnings conference call. A replay of today’s conference will be available and information for this was provided in today’s press release. ACT would like to thank you for your participation. You may now disconnect.

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Source: Pioneer Energy's CEO Discusses Q3 2012 Results - Earnings Call Transcript

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