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Executives

Anne Pearson – IR, DRG&E

Stacy Locke – President and CEO

Lorne Phillips – EVP and CFO

Analysts

Jim Rollyson – Raymond James

Steve Ferazani – Sidoti & Company

John Daniel – Simmons and Company

Brian Uhlmer – Pritchard Capital

John Keller – Stephens Investment Management

Pioneer Drilling Company (PDC) Q1 2010 Earnings Call Transcript May 6, 2010 11:00 AM ET

Operator

Good morning, ladies and gentleman. And thank you for standing by. Welcome to the Pioneer Drilling first quarter earnings call. During today's presentation, all parties will 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, May 6, 2010. I would now like to turn the conference over to Anne Pearson of DRG&E, Investor Relations. Please go ahead, ma'am.

Anne Pearson

Thank you, Mitch, and good morning, everybody. Welcome to Pioneer Drillings conference call to review first quarter results. Before management makes their formal remarks I have a few of the usual items to cover.

First, a replay of today's call will be available and is accessible by webcast, by going to the Investor Relations section of Pioneer's website and also by telephone replay through May 13th. You can find all of the replay information in today's news release.

Information recorded on this call speaks only as of today May 6, 2010, so any time-sensitive information may no longer be accurate as of the time of any replay. Management may make forward-looking statements today that are based on its beliefs and assumptions and information currently available to them.

Although management believes the expectations reflected in these statements are reasonable, they can give no assurance that they will prove to be correct. These statements are subject to certain risks, uncertainties and assumptions which are described in this morning's earnings release and also in the most recent filings with the SEC. Should one or more of these risks materialize or should underlying assumptions prove incorrect, actual results may differ materially.

Please also note that this conference call may contain certain references to non-GAAP measures. You can find reconciliations to the GAAP financial measures in Form 8-K as well as in this morning's news release.

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

Stacy Locke

Thank you, Anne, and good morning. Joining me on the call this morning is Red West, our President of the Land Drilling Division; and Joe Eustace, President of the Production Services Division; and Lorne Phillips, our Chief Financial Officer.

While this first quarter was below our expectations in really everything revenue, EBITDA, and net loss, many of the contributing factors in this quarter were, what I believe are non-recurring and I'm going to go through those. And a lot was accomplished during the quarter, which I think will pay dividend in quarters to come.

I’d like this morning to talk briefly about EPS, because that's a shorter conversation. The production services businesses performed better than expectations. We were anticipating 5% to 7% revenue growth and it came in over 13%.

We were anticipating flat margins and they just picked up slightly, but did show modest improvement. All of the sectors performed in the quarter wireline really performed well this quarter, lots of activity.

The well servicing group continues to perform well. They were averaging 53% in Q4, and averaged 60% in Q1. And amazingly today, they are operating at over 80%. So that is building – that business is building nicely.

As well, well, the average hourly weight – rate for well servicing declined from 453 in the third quarter. We had a little anomalous bump in Q4 to 470, and we were back down to 444 average hourly rates in the first quarter. But that's holding firm, it was mostly due to a shift of some rig to lower margin areas, just due to activity changes. But it is holding firm there and we might see some increases as we move forward.

Fishing and rental, although still struggling, fish showing signs of improvement and did improve a little bit in the first quarter, compared to fourth quarter as well. So overall, EPS was a big contributor during this first quarter of the year and continues to perform well in second quarter.

Looking at land contract drillings, we actually exceeded our expectation and utilization of 45% to 47%, and finished the quarter an average of 49%. And we continue to have, what I’d called very steady improvements since then and we are currently running at about 61% utilizations today.

Where we really got hurt was our margin. Revenues were down and costs were up, and we had a lot more percentage of mobilization days in the quarter, relative to revenue days on certain rigs and that's, what I'm going to kind of walk through some of those specific issues that we dealt within the first quarter.

First, turning to Columbia. We mobilized our sixth and seventh rig into Columbia. Those were delayed, getting to location, and getting rigged up in part due to the fact we were continuing to finalize our contract terms with our customer there, as these rigs were moving until we sold out for a while as were finalizing these agreements.

And then, once we got to go ahead, they start moving rigs to location due to the fact that these are different types of contracts then what we’ve had in the past. They took longer to – and I would say, that our customer paid little more attention to the customization to the rig that they preferred, and so that took a little more time, money, labor, to get kicked off.

But we did get both rigs started in March and they experienced as customer rates are – high start up cost and that first – on that first job, these startup costs were excessive relative to our expectation. So we were both delayed and the start-up costs exceeded our expectation and it was costly.

Now the rigs are running and we think they are getting line-up, should perform well from this point forward. I might add, both of those rigs, as part of rig-up process, rigged up, one with the skidding system and one with the walking system, which added a little bit of timing to the process.

Also in Columbia, we took an existing rig there and put a walking system on it, as part of rig move. So, the rig was either moving or having a walking system put on it for over 60 days, the walking system process took little over 30 days. But it does require expensive mobilization to the area where you want to work on the walking system and crews to do the work and it was costs. And as part of our contract with our customer down there, we are putting walking systems or skidding systems on all of our eight rigs there.

But anyway, we had the walking system installed during that quarter. So that rig was not earning revenue during that period and we installed the skidding system on another rig during that quarter. So that period of time we were down, not earning revenue and we initiated a third walking system upgrade towards the end of the third quarter and that’s ongoing today. So we are systematically going to the rig and putting these walking systems on and that just takes time and money.

Also while we had the rigs in a free zone, we decided to reload those rigs in fact on our five-year importation into the country for that purposes. So these rigs are operating under a five-year importation implication rule and that these rigs have been in Columbia for several years and we’re entering three-year term contract, we thought it would be appropriate while we had them in a free zone to go to the process, carry the additional rig component to the free zone and reestablish the rig for another five years to avoid having to pay to that tax and that’s what we’ve done on two of those rigs.

We hope to do that again on two additional rigs down the road, hope to be able to do four, five existing rigs in that same manner but we’re still working to that on the other two rigs.

But nonetheless, all of that process takes time and money, and it all happened in the quarter, in addition to the mobilization of the sixth and seventh rig. And currently we are mobilizing from the fourth, our eighth and final rig, as part of this contract, and it is heading the location as we speak and we will be rigging up and we anticipate a smoother process there for that rig.

We had similar types of issues in Appalachian part within our control, but was not in our control, but we moved our fourth and fifth rig to the Appalachia, one left at the end January 1, one beginning of February and we are met with a historically tough winter lots of snow delay, truck was stopped and we are our incurring labor cost during that time and we delayed in making more complicated to rig up the rig as well as into those condition. And it affected our other three existing rig with respect to their rig moves and activity.

In addition, there just like in Columbia, those two rig not only did the normal rig up in adverse weather conditions but they rigs up on skidding systems for the first time. But we now have those two rig with skidding systems and the start-up cost where a little higher on those initial job there as well as in Columbia.

So that’s kind of the bad news. the good news is a lot of that’s been done and so when you look in fact at Columbia as I mentioned it will improve by the third quarter, we will have seven of the eight rig with other walking or skidding systems and we will be doing the eighth rig in the fourth quarter. But that will be largely behind us and what that means for is that in the future, these rig will be on pad type and the mobilization will be shorter and therefore you will have less risk of all the things that occurred during mobilization, lighting on trucks and complicated write-downs or rig moves and potential weather but anyway so they will be working on pad side and we will see the revenue they shift substantially more towards they work revenue day than mobilization revenue day.

So that’s going to be a big benefit as we move into the future. Same kind of process in Marcellus Shale as I mentioned the two rig we just shift up there are on skidding systems. We’re anticipating putting two more skidding systems on probably in the third quarter. So four of the five rigs entering into next winner will have skidding systems, which will increase the efficiency there and we have a six rig in Houston, don’t yet have a contract firmed up for it but that rig will be rigged up with a skidding system as well. So these things we will add a lot of improved economics for all of the related rigs in the future.

Besides the skidding systems that I talked about during the quarter, we also added four top drive, five are on rough mix, three pairs of 1600-horsepower mud pumps that’s a total of six rigs – six plus there and three pairs of 1300-horsepower mud pump. So that’s a total of 12 mud pumps that we will upgrade fixed rig for the shale activity.

So when you set back and look at what we’ve done over the past four quarters. We have installed a total of 15 top drives, 10 pairs of higher hydraulic horsepower mud pump and nine walking or skidding systems on our rig. So it’s a very substantial transformation of the fleet to make them more efficient rig in shale plays.

With respect to top drives specifically today, we have 26 rigs with top drives at 37% of fleet and we will install two more top drive this month and we have fix more on quarter. So by the third quarter, we will have 34% or 48% of our fleet offset as a top drive.

As you might imagine for me discussions are capital expenditures are front-end loaded for this year. We have spent committed to quite a bit of our 2010 capital budget in the early part of the year. That’s bad news, but the good news is it will increase our regularization and increase our day rates because all of these up rates correspond to substantially higher day rate.

As an example of that, in day rates what are seeing today, the forward day rates for 1000 or 1500 horsepower electric top drive rig within rate in accept of 18000 a day for 1000 to 1200 horsepower mechanical top drive rigs. We are seeing rates in excess of 16000 a day.

And for the non-top drive mechanical rig that have not yet been upgraded, the rates are still in the 10000 to 13000 a day-day rate range. So you can see that the upgrade of the pump and up the top drives will contribute to substantial improvements in margin and that’s what we are anticipating seeing in the second quarter and the third quarter of this year.

I would like to quickly comment on couple of other of our strategic initiatives as we mentioned in the press release, our activity that relates to oil drive business is up substantially and we made strategic move starting really in about 2004, late 2004 with our acquisition in the Bakken to gradually over time diversify our business to a more 50-50 mix of oil and gas generated business from a 100% natural gas driven business.

And so today 56% of our active rigs are drilling for oil and we believe in excess of 40% of our revenues are now derived from oil through drilling and production services.

In addition, a more recent initiative as we talk about on our last quarter call was desiring a greater percentage of term contract mostly as it relate to uncertainty and gas prices. But today, we have got 21 term contract that’s 49% of our active rig and we have two more time contract ending and range in link the U.S. average term link is six months, Columbia is, I mean excuse me, nine month. Columbia is 26 months for our company average of about 15 months.

So we are continuing to push more terms, we are possible but we do have an upstart exposure to take advantage of the increase in day rates. I would like to turn the call over to Lorne now for quick recap on the financials.

Lorne Phillips

Thanks, Stacy. Good morning, everyone. In the quarter, Pioneer had a net loss of $14.5 million a $0.27 per diluted share. This compares to a net loss of $11.9 million or $0.23 per share in the prior quarter, when the prior quarter adjusted to exclude a $3.5 million tax benefit from the release in evaluation allowance on deferred tax asset.

Consolidated revenue for the first quarter was $86 million which is up $4.8 million from the fourth quarter. Our EBITDA was $9.2 million versus 14.1 in the prior quarter. Drilling services revenues were 55.8 million, which was an increase of 1.2 from the fourth quarter.

Columbian revenues were $15.7 million of that total and turnkey revenues were almost $4 million. The turnkey business included four completed jobs and two jobs in progress at the end of the first quarter. Because our last contract that was earnings stand by revenues expired on December 31. We did not have any drilling revenue from this category in 2010.

Our drilling services cost were up 16% from the prior quarter, which reflect items safety, we’re discussing, the extra cost associated with delay and getting rigs to work as well higher rig cost in Columbia. Weather delays in mobilizing rigs in the Marcellus and higher repair and maintenance expense due partially to putting ideal rigs back to work.

Drilling services gross margins were just under 18% compared to 28% in the prior quarter. The margin per day if 3145 was down 44% from the fourth quarter, again, due to the deployment delays and higher cost I just describe as well as some of the increase utilization quarter-over-quarter were in areas that have lower day rates such as East Texas and non Eagle for South Texas.

Production services, revenues for $30.2 million, up 13% and the gross margin with $10.2 million slightly higher margin percentage of 34% from the prior quarter. We saw improvement across the board in production services but Wireline was the largest contributor to the revenue growth.

I will move on from there. Stacy has cover the lot of a detail on the utilization rates on in hourly rate and wealth servicing. Our companywide SG&A costs were $11.5 million in the first quarter. This was higher than we had guided, driven by higher activity levels. We ended up bringing more people on staff, more quickly than we originally anticipated. Our stock compensation expense was little higher than expected as well.

For the year, we now anticipate SG&A will be closer to $48 million. Our effective tax rate in the first quarter was 38.6%, driven higher by tax benefits in Columbia. For the full year, we expect the tax rate to now be closer at 35%.

Moving on to the balance sheet, during the first quarter we sold senior notes that raised the net $234.8 million, which we used to pay down in the majority of our revolving credit facility. We also received proceeds of $40.6 million in April, related to an income tax recovery.

We currently have $12.8 million drawn on our $225 million credit facility, plus an additional $9.2 million of letters of credit. The new balance reflects the pay down we made using proceeds from the notes as well as an addition of $10 million payment using proceeds from the tax benefit. As a result of these changes in the capital structure, we expect interest expense to approximately $7.4 million to $7.6 million on a quarterly basis going forward.

Our cash and cash equivalents at the end of the fourth quarter were $11 million which is down about $29 from December 31. The decrease is due to capital expenditures of $25 million in the first quarter and $4.2 million net cash we used in operations.

At the end of the first quarter, we were in compliance with our financial covenants under our facility. Our total consolidated leverage ratio was 4.49 to 1. Our senior consolidated leverage ratio was 0.5 to 1 and our interest coverage ratio was 5.65 to 1.

Given the increase in activity from our prior quarter recall, we have increased our 2010 expected capital spending from an earlier range of $70 to $85 million, to a range of $90 to $100 million. This increase is expected to go towards addition of topdrives and rig upgrades to make us more competitive for working the shale plays. As Stacy mentioned, the addition of this equipment allows us to increase our day rates and generate higher margins.

With that I'll turn it back over to Stacy.

Stacy Locke

Thank you, Lorne. In closing I would just like to underscore our second quarter guidance that was identified in the press release. For the drilling services division, we had 49% utilization in Q1, in regard to 58 or 60% utilization in the second quarter. And our average margins, we think are going to come up. We are estimating in the range of 4500 to day, to 5000 a day, and margins we drilled that back a little bit just because of knowing that we have another rig starting up in Columbia and we got two more skidding systems been put on there. Hopefully, that's conservative.

On the production service side, for Q1 in regard to 5 to 7%, ended up 13%. We are going to take the guidance up to 8 to 10% revenue and we are going to guide the potential for a modest increase in margins, quarter-over-quarter. They reflect to up 2%.

So pretty comfortable with that guidance, I would like to think it’s conservative, but we are little stunned after this quarter, but usually, we are proud of ourselves on having good guidance.

So at any rate, I would like to end the prepared discussion and open for questions at this time. Operator?

Question-and-Answer Session

Operator

(Operator Instructions). And our first one comes from the line of Jim Rollyson with Raymond James. Go ahead, please.

Jim Rollyson – Raymond James

Good morning, Stacy.

Stacy Locke

Good morning, Jim.

Jim Rollyson – Raymond James

How are you doing?

Stacy Locke

Pretty good.

Jim Rollyson – Raymond James

I guess. My first question is with respect to the growth in CapEx for the year, which I think you noted it was mostly going to go towards topdrives. Can you give us some sense, or maybe if you run the math on kind of the payback period on buying the new topdrives that were replacing the rentals that you got now, how that's working out?

Stacy Locke

Okay. Lorne, do you want to?

Lorne Phillips

Sure. Those generally, when we look at those we believe the payback is in a two to three timeframe. And of course it depends on the rate that we are seeing, and when you put it into work in shale plays, those higher rates on the topdrives, we think the cash payback is probably closer to three years.

Jim Rollyson – Raymond James

Okay. That's good. And then with regard to the skidding systems and walking systems, maybe first of any magnitude of what the cost of those systems are and is this something you get paid back from contracting or standpoint or is this more of a cost savings slash efficiency prices of asset.

Stacy Locke

Well, in some cases we are able to increase the day rates to help, reimburses for that cost, we've had that happened in the past and where we can't, we did obviously. We ask for compensation to cover that – to pay that cost. And the actual cost ranges, I think the skidding systems run in the 600,000 range and walking systems are probably 900,000, so they are pre substantial cost. And we think that – we’re one that's what the customer wants, so.

If they are going to impact drilling, you either put it on or you don't do the work and then you hope to recover some of the cost through the increase day rates. And then certainly as I have mentioned in the prepared remarks, you will recover some over time through the improved efficiency of the rigs. And you'll have more days, earning the full day rate as opposed to mobilization rates.

Jim Rollyson – Raymond James

Sure. Well that goes for both, Columbia and up in the Marcellus as well.

Stacy Locke

Really, everywhere. They are so much – We’ve had – the great loser, less than 24 hours, in some cases rig would state it less than half a day. So instead of, like in Appalachian where we sometime have shortages of truck and complicated move. Those move might take four or five days, well, now you can move in, in potentially less than 15 hours or so.

Jim Rollyson – Raymond James

Right.

Stacy Locke

So that really improves the – and it takes out so much uncertainty in any weather, climate risk area like North Dakota, Utah, Appalachia and incidentally we have a walking system on the rig in Utah as well. We are probably going to put skidding system on another rig there. But in any of weather as related areas, or down in Columbia where move – they are just difficult. It's long and takes a long time. I think that it's clearly going to be a benefit down the road.

Jim Rollyson – Raymond James

Sure. Thank you very much.

Operator

Thank you. And our next question comes from the line of Steve Ferazani with Sidoti & Company. Go ahead, please.

Steve Ferazani – Sidoti & Company

Good morning, Stacy. Good morning, everyone. I'm trying to get a sense of – you've turned up a lot of rigs, but are they in the places where rig counts are going up or have you turned up in a more vulnerable gassy locations. What I'm trying to do is get a sense of how vulnerable you are, to not getting the benefit from an upward trend and utilization for the year?

Stacy Locke

Well, that's a good question. All of the rigs in Columbia are turned. I would say in Marcellus, I think three of the five are turned. In the Bakken, those rigs are turned and in Utah, those rigs are turned. And in South Texas, we have just a little bit turn. Mostly that is passed. Rich is sending advantage to us because that's where we are seeing probably the greatest delta in day rates change. And of course as oil as in our backyard has been a very strong area for us, so that's one area that we are more comfortable having less terms.

Steve Ferazani – Sidoti & Company

How much of your rigs in South Texas or Eagle Ford versus non-Eagle Ford at this point?

Stacy Locke

I think six of the rigs are in Eagle Ford proper but we probably have another four rigs there that are drilling horizontally, that are in other closely related formations, Greenrose [ph], some – anyway, Georgetown, but, so we have those six in the Eagle Ford for sure, most of which in the oil.

Steve Ferazani – Sidoti & Company

Okay.

Stacy Locke

I think may be all are in the oil but…

Steve Ferazani – Sidoti & Company

In the past you have mentioned, I mean, obviously, given the success of Columbia, you considered other markets, where do you stand now on that?

Stacy Locke

Well, since we’ve had such a ramp up here in the U.S., we have spend quite a bit of money operating 30 rigs for the U.S., we’re kind of at a point where we like to see some of the cash flow come cascading in before we are going to keep entering now. So we’re going to probably funding low this CapEx first half of this year and then slow it down and let the EBITDA build back up and then address other areas.

Now having said, we are identifying markets in other areas that we think offer potential for us in laying the ground work more for 2011, 2012 cost activity. And that’s I think our primary markets would, while we look at a lot of market, where, I would say, we are in South America.

Steve Ferazani – Sidoti & Company

And the ramp in Columbia is finish now. I think that’s you pretty much with FDA.

Stacy Locke

We’re pretty pleased with our exposure there and preference would be to move into other countries and/or in Columbia increase some other of our services, like production service.

Steve Ferazani – Sidoti & Company

Thanks a lot. Thanks, I appreciate.

Operator

Thank you. Our next question come from the line of John Daniel with Simmons and Company. Go ahead.

John Daniel – Simmons and Company

Good morning, guys.

Stacy Locke

Good morning.

John Daniel – Simmons and Company

Couple of things, you mentioned that you receive the packages. Are those on rigs that are working today and those going to on full rig that are preparing to deploy?

Stacy Locke

Well, they are both. Some of the rigs I’d sat probably half or more are rigs that are working but by putting this package are no long a part of a improve economic higher Day rate program for ourselves. But there are rigs that we have take that are fact like the mechanical rigs and foot with bigger pumps and the top driving put it the work where if I was working before, we are running much day rate or earnings much day rigs or work run either so, we have mixture of both.

John Daniel – Simmons and Company

Okay. I just trying to look out beyond Q2 in terms of the utilization, all of been equal, you mentioned you got one rig, eight rig can be embedded to the (inaudible) looking at contract coverage, you got 21 rig under contract, now going to 23. It seems like as we get to the end of quarter, we might see three to five more rigs or something like that going out such that Q3 utilization could be low-to-mid 50% on drilling side. Is that reasonable?

Stacy Locke

I think that is reasonable. We are not dying out that far but that would be an obvious conclusion. And beyond that, there is greater uncertainty just because you- one end the gas price and then we are dealing with more of our mechanical at this point. So it will be more gradual increase, if in fact, there is an increase because you still have some rigs that are on spot drilling in gap areas. So we’ll just have to wait and see how that plays out but we’re not overly optimistic on gas prices so we’re continuing to focus more on the shale, particularly oil shale and we think there is, these mechanical rigs are doing great in the shale. I mean, we’ve got five of them – we’re top drivers now and they’re performing very well, earning very good day rate. We’re going to continue with that effort through the course of the year.

John Daniel – Simmons and Company

Let's just say gas price did cause the people to drop some of these spot rig, presumably some of your spot rig at the lower cash margin such that (inaudible) doesn’t have significant impact from (inaudible).

Stacy Locke

From an EBITDA stand point, actually what it would do, it would partly affect EBITDA and it will improve our average margins per day. Those are earnings, very, very low margins relative to all of the upgraded top rated oil rigs.

John Daniel – Simmons and Company

Okay. Just a few more. But on the CapEx (inaudible) lines, can you give us a sense of what should expect from DD&A rate as we go into Q2? If you stated that I must apologize.

Stacy Locke

You know, I didn’t say I would say to around 116 million for the year as we go up. So you can take first quarter and kind of ramp it up that way.

John Daniel – Simmons and Company

Fair enough. And then the last one from me is given the availability on the credit facility which is pretty significant, let’s say things steady state note drop off and activity, is your preference to grow an incremental CapEx, would you fund that the other revolver or does that gives the availability take any concern about follow-on equity offering off the table.

Stacy Locke

Well, we don’t plan – yeah, in our – taken of the table if we needed more in our facility, it would be the short-term working capital at the end would paid back.

John Daniel – Simmons and Company

Okay.

Stacy Locke

And we do not plan on doing equity offering. We really focus on – we've done a lot for these rigs. The rates are going up and we’ll slow up CapEx for during the year and build the cash flow.

John Daniel – Simmons and Company

Cool. That’s it. Thanks, guys.

Stacy Locke

Okay. Thank you.

Operator

Thank you. And our next question comes from the line of Brian Uhlmer with Pritchard Capital. Go ahead please.

Brian Uhlmer – Pritchard Capital

Good morning, gentlemen.

Stacy Locke

Good morning.

Brian Uhlmer – Pritchard Capital

Hey, just trying to get better understanding of overall market, what are you private customer’s asking, there you’ve seen a man come down a little bit current gas prices part of the public price rate are doing?

Stacy Locke

I would say the majority of our customers are the public company but we have good progress. The company does well and I would say the activity levels are still strong degree down. So I mean this levels continues to be strong really in all of these area that there is rig demand in the (inaudible) there is rig demand in the Popin [ph], there is rig demand in the Eagle Ford that’s probably been the biggest crisis that how much demand will come from Eagle Ford. We have shifted even rigs from the Haynesville area down to the Eagle Ford and it’s – we like that because it’s we’re mostly in oil there and it’s so close to our office and our operations are so strong and cost is lowest from South Texas so it just really makes a lot of finch for us, continue to pursuing activity there but the demand is high and rates have firmed up and so we haven’t any really gas price concerns so far.

Brian Uhlmer – Pritchard Capital

Okay. Let me guess, say, in Texas, what you guys (inaudible) I guess, opportunities that are incremental rigs are working with less factors growing for oil?

Stacy Locke

Well, that’s a great thought. Activity is booming there. We have historically not been there just because it hasn’t been our equipment orientation of higher end, more modern fishing equipment is, it’s not necessary out there, the customers don’t really require it but we’ve shied away from it. However, now that oil is looking like a much on a relative basis more favorable commodity, we are actually exploring that because our mechanical rigs would be very high-end rigs there because we’ve all triplex mud pumps, round a bottom mud (inaudible) that are automatic – excuse me – iron rough mix bottom and they would be very strong with Texas rigs. We are considering that.

Brian Uhlmer – Pritchard Capital

Okay. In previous liquidity position, are you guys, with your rig acquisition, you’ve build anything like that right now.

Stacy Locke

We’re always looking for good strategic fit from an acquisition front but right now we’re not planning any new bills just because we spend a lot of money and we want to let the EBITDA build up with improved day rates and like that something we will certainly look at next year and year after.

Brian Uhlmer – Pritchard Capital

Okay. And last question from me. Turning to the production services side of the business. Can you give us a little more detail on which markets and particularly seen improved demand for wireline and its relations out of the jumps we considerably with us something as well?

Stacy Locke

Well, I would say the wireline activity is up across the board where in lots of different types of markets but one area that it really help us from a revenue and EBITDA perspective is our expertise in the long latter of horizontal work our team, we do a lot of the – what they do they pump down the completion tool corporating guns in the long lateral completion multistage frac job and that’s really an area of expertise for us that we are leader in that, in the Bakken, in the Bonnet, in the Haynesville, in the – we are developing it in the Marcellus and we are developing it currently in the Eagle Ford.

So it just that’s kind of where our strength is and that’s what we are levering off of so that’s we are a lot of that big tickets come from and then on the work over front, I would say activity is up there across the board. We have been real pleased with our expansion there again into the oil market, back in to the Bakken over into mid to 50 to last Warrior Basin [ph] and now we are working in the Eagle Ford is well. So we really enthusiastic about what we are seeing in those markets.

In fact we mentioned in the press release we have originally coat activity of our rig were down to three now and we are anticipating that potentially by the end of this current quarter those three rigs will also be out working. They will be operating the full 74 rig fleet as we enter in the third quarter so we are very excited about that. We are seeing considerable activity there.

Brian Uhlmer – Pritchard Capital

Okay. Appreciate it, something.

Stacy Locke

Thank you.

Operator

Thank you. (Operator Instructions) Your next question comes from the line of John Keller with Stephens Investment Management. Go ahead, please.

John Keller – Stephens Investment Management

Hey good morning, guys.

Stacy Locke

Good morning, john.

John Keller – Stephens Investment Management

I was just curious if we look at your fleet right now how many rig are still candidates for more upgrades?

Stacy Locke

Well, I think you can approach that from the other direction I cant to say how are not candidates. So we have 71 in total I would say five of the six cold frac rigs in Oklahoma, Western Oklahoma are not candidate those are very low horsepower rig and then another five or so of our smaller mobile cavetsol rig [ph] cata 750 , 900 are really not suitable. They have very, very good rig they are pretty much all working right. But the math a little light for top drive activity.

So outside of that they are probably or a few another three to five that we might choose not to spend the money on top drives and bigger pumps on because they are light either in map or you have to put a new map but I would say outside of the 71 I would say pretty much all but 15 our candidate to be upgraded.

John Keller – Stephens Investment Management

And how many of has significant upgrade work already of the remaining where the number that is?

Stacy Locke

Of the conventional fleet I think the of the mechanical rig I think we put top drive on five of those rigs again we are considering others currently.

John Keller – Stephens Investment Management

That’s all I have. Thanks, guys.

Stacy Locke

Okay. Thank you.

Operator

Thank you. And we have no further audio questions at this time. I would like to turn the conference back over to management for any closing statements.

Stacy Locke

All right. Well, that will do it. Thank you all very much for participating on the call this morning and we will look forward to more rosy second quarter call. Thank you.

Operator

Ladies and gentlemen, this concludes the Pioneer Drilling first quarter earnings call. Details for the today’s recording can be found in this morning’s news release. You may now disconnect. Thank you for using ATP teleconference.

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Source: Pioneer Drilling Company Q1 2010 Earnings Call Transcript
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