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Executives

Anne Pearson – IR

Stacy Locke – President and CEO

Lorne Phillips – EVP and CFO

Analysts

John Daniel – Simmons & Co

Brian Uhlmer – Global Hunter

John Keller – Stephens Inc.

Roger Read – Morgan Keegan

Donald Lacombe – SVP, Marketing

Marshall Adkins – Raymond James

Pioneer Drilling Company (PDC) Q3 2011 Earnings Call November 3, 2011 11:00 AM ET

Operator

Good morning, ladies and gentlemen, and thank you for standing by. Welcome to the Pioneer Drilling Third Quarter 2011 Earnings Conference 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, November 3, 2011.

I’d now like to turn the conference over to Anne Pearson with DRG&L Investor Relations. Please go ahead ma’am

Anne Pearson

Thank you, Mitch and good morning to everyone. Before I call – I turn the call over to Pioneer CEO, Stacy Locke and to CFO, Lorne Phillips for their formal remarks; I have a few usual items to cover. First of all replay of today’s call will be available and accessible by webcast by going to the Investor Relations’ section of Pioneer’s website and also by telephone replay. You’ll find the details on how to access those replays in this morning’s news release.

Also as a reminder, information reported on this call speaks only as of today, November 3, 2011, so any time sensitive information may no longer be accurate at the time of the replay. Management may make forward-looking statements today that are based on beliefs and assumptions and on information currently available to them. Although they believe the expectations reflected in these statements are reasonable, but there is no assurance that they will prove to be correct. They are subject to certain risks and uncertainties and assumptions that are described in this morning’s release, and also in recent public filings with the SEC.

If one or more of these risks materialize or should underlying assumptions prove to be incorrect, actual results may differ materially. Also please note that the call may contain references to certain non-GAAP measures, you’ll find reconciliation to the GAAP measures in this morning’s news release.

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

Stacy Locke

Thank you, Anne and good morning everyone. Joining me on the call this morning is Red West, President of our Drilling Services division; and Lorne Phillips, our Chief Financial Officer. With respect to the quarter overall another very nice quarter for the company, top line revenue was up another 10% after being up 12% in the second quarter. EBITDA was up 14% to 52 million, after being up 16% in the second quarter. As in our second quarter, the Production Services division was the big driver for both revenue and EBITDA growth for the third quarter.

Looking at our Drilling Services division, some of the things going on there, as the press release stated in October we sold four of our lowest horsepower rigs that have been stacked in Western Oklahoma since about the summer of 2008. As you recall, we had six back there and we have been successful this year inactivating two of those six, the larger horsepower rigs, and mobilizing them to work in West Texas.

But the other four were at roughly a 550 horsepower and we just – they were non-core strategically to the company, and we made a very successful sale of those rigs in October. In addition to those four, we have put in auction for this month, two additional rigs or really what I would call fragmental rigs and those will be sold this month in auction. And then we have a seventh rig where we are not selling the mass sub and carrier, we’re going to keep that as spare equipment in our yard for the potentially reactivation at some point into the future.

So, that takes our marketed fleet down from 71 to 64 rigs, so we are down seven, and the entire fleet is now a good solid marketed fleet. Today we are actually operating that fleet at 88% utilization, all 14 of our rigs in the Permian are active and utilized under contract, all nine of our rigs in the Bakken are active, all seven of our rigs in the Marcellus shale are active, all eight of our rigs in Columbia are active, and both of the rigs in the Uinta Basin are active as well. And we are in the process of working on two additional 60 series rigs to mobilize for long-term contract in the Uinta basin.

In South Texas, 13 of our 14 rigs are utilized. We have one mechanical and 50 down for a short period of time, most of these rigs are working in the Eagle Ford shale. East Texas is really our only soft market. Today we have four of the seven rigs back in East Texas, three working. It continues to be a weak market gas oriented drilling.

In addition to these active rigs, we have three rigs in Houston being ready for distribution into other markets. Two of those are rigs that are being worked on and upgraded a little bit for West Texas, where we hope to have those two rigs working there by the end of this year. And we have one 60 series rig from South Texas being winterized and ready for its move to Utah in December.

On the new build front, as the press release stated, we signed an additional three 1,500 horsepower AC pad drilling rig, all on three year term contracts. So that’s a total now of nine rigs that are under construction to be delivered during 2012, seven of those are 1500 horsepower AC rigs, two are 1,000 horsepower AC rigs, all are walking rigs.

So that will take during 2012, rig fleet back up to a total of 73 active market rigs during the course of next year. Overall demand remained strong for drilling services. Day rates are firm and we continue to roll over term contracts mostly on six-month and one-year terms. I would say it’s about evenly split between the two and we’ve even recently signed a two-year term. So we have about 70% of our working rigs today under term contract, and with the term that we know they are about to begin, we should be up to over 75% operating in a term contract shortly.

Turning to our productive services division, we had another outstanding quarter, revenues up 22% after being up 21% in the second quarter. Margin as a percentage of revenue was up 2% to almost 44% and all three of our business lines in production services, wireline, well services and fishing and rental should EBITDA growth and an increase in margin as a percentage of revenue. So we just had another terrific quarter there.

We also have made two small tuck-in acquisitions. One was in well services where we purchased two working 600 horsepower rigs that we had been newly built and we have since added a third unit to that area and then we purchased a two unit wireline company as well, both of these tuck in acquisitions were strategic in nature establishing us a new markets.

We continue to grow both well services and wireline today, and well services were at 86 units and we have two additional rigs coming there at the very end of the year and so we will end the year at 88 and then we have ordered 16 additional units for delivery by summer of next year. In the wireline business, we have got 103 units today. We have three and possibly four additional units that will be here by the end of the year and so we – and then we have five. So we should end the year if the delivery of that last unit makes it on time at 107, with five additional units ordered for delivery in the first quarter.

So we like what we see in the production service segment of our business. Just like in drilling, the demand is strong, and we continue to see study, although slow improvement in pricing and margin. Coming up in the fourth quarter and possibly the first quarter, we will be subject to our normal cyclicality, but we do see continued improvement in that market.

At this point, I would like to turn it over to Lorne to go into a little more detail on the financials.

Lorne Phillips

Thanks, Stacy. Good morning, everyone. As you saw on this morning’s earning release, we reported third quarter net income of 6.7 million or $0.11 per diluted share. And that compares to net earnings in the prior quarter of 3.7 million or $0.07 per share and a net loss of 2.6 million or $0.05 share in the third quarter of last year. The third quarter net results included the impact of a $1.2 million pre-tax foreign exchange charge related to our Columbia operations as a result of the US dollar strengthening compared to the Colombian peso.

We also had an impairment expense of approximately 500,000 related to the seven drilling rigs that we are retiring from the fleet. We do expect to realize net cash proceeds of about 2.6 to 2.8 million for the six rigs that we are selling. Our consolidated revenues in the quarter totaled 187.7 million, which was up about 10% from the prior quarter and up 38% from a year ago. Our adjusted EBITDA totaled 51.6 million, an increase of 14% from the second quarter and up 51% from a year ago.

Overall revenue from our drilling services operations totaled 108.8 million, which is up 2% sequentially. Colombia accounted for 28 million or approximately 15% of that total. The margin for our drilling services division was 36.3 million in the third quarter, an increase of 9% from the previous quarter. And the average drilling services margin per day increased almost 4% sequentially to 7,797.

The third quarter improvement in margin per day reflects reduced downtime on our US drilling rigs and reduced drilling rig start-up costs since more rigs were activated during the first half of the year. As Stacy mentioned, our current utilization is around 88%, and please note that this utilization is now based on a rig fleet of 64 drilling rigs.

If you went back and excluded the seven retired rigs to calculate our third quarter utilization rate, it would have been 79%. Our turnkey work increased slightly in the third quarter. We completed five turnkey jobs versus four last quarter and turnkey revenues totaled about 4 million.

As of this week as Stacy mentioned, 71% of our working rigs are operating under term contracts. The average remaining term on these contracts is approximately seven months in the US and eight months overall.

Looking now at the Production Services division, the revenues increased 22% sequentially, driven by higher rates, increased units in the fleet, and higher overall utilization. The margin in production services was 34.5 million, which is up 28% compared to the prior quarter. And as a percent of revenue, the production services margin was 43.7%.

Overall contribution by production services to the company’s total revenues and total gross profit continued to expand in the third quarter, representing 42% of the company revenues and 49% of the company’s gross margin. The utilization rate for the well servicing units was 92% during the quarter compared to 90% in the second quarter, the average hourly revenue rate increased by 6% to 555 an hour in the third quarter. And in October, the average hourly rate was 587 an hour and utilization was 91%.

I would note, as Stacy mentioned as well, the third quarter does tend to be one of our stronger quarters for the production services business, in large part due to favorable weather and increased daylight hours.

Moving on now to our overall expense trends for company, our general and administrative expenses were 17.7 million, which was up about 12% from the prior quarter. The increase is driven by higher accruals for incentive-based compensation. We expect our fourth quarter SG&A to be in the 18 million to $18.4 million range. Depreciation and amortization expense was 33 million, which was up about $0.5 million versus the second quarter. Our D&A for the full year should be in the 132 to 134 million range.

Interest expense for the quarter was 6.1 million, which is down almost 2 million from the prior quarter. The decrease was driven by a few items, including the result of the zero debt balance on our revolver due to the equity offering in July. And we also capitalized interest of 1.1 million due to our rig build projects. And finally, the second quarter had included a $0.6 million charge related to the credit facility amendment which did not repeat in the third quarter obviously.

Our tax rate for the third quarter was 43.7%. The higher tax is related to foreign exchange losses associated with our Columbia operations. We expect our tax rate to be in the 38 to 40% range for the fourth quarter, again, prior to any potential impact of foreign exchange gains or losses.

At September 30, we had cash and cash equivalents on the balance sheet of 21.9 million, and nothing outstanding on our $250 million revolver, other than 9.2 million in letters of credit. We do expect to begin drawing down some funding again on the revolver late in the fourth quarter or early in the first quarter of 2012 to pay for the additional drilling rigs and production services equipment.

During the third quarter, we spent 61.4 million on capital expenditures, of which approximately 9 million was for routine CapEx. Our current full year CapEx spend estimate continues to be 200 to 220 million.

And now I will turn it back to Stacy. Thank you.

Stacy Locke

Thank you, Lorne. Just very briefly, on our outlook and guidance, I think we remain positive on what we are seeing in the market. We are all cautious just about oil prices, but as far as it’s affecting our business, we are seeing virtually no affect and continued strong demand in really all of our business lines. So we continue to be cautiously optimistic.

Our guidance on drilling as we identified in the press release, we think our utilization for the fourth quarter will average 87% to 89%.

When the three rigs that are being readied in Houston go back to work which should be in December and really affecting more the first quarter, that will put us up into the low 90% utilization. And then we are marketing a couple more of the rigs that are currently stacked in East Texas into some other markets. So we’re optimistic we can bring that utilization solidly up into the 90s by the first quarter of 2012.

With respect to margin, basically the same story we’ve been saying the last few quarters. There’s not a lot of change in our market there other than we are moving more equipment to work in West Texas which is at a lower day rates and a lower average margin.

We gave guidance last quarter to be kind of flattish to down a little bit. We were actually up almost 300 per day in average revenue – in average margin. And part of that, as Lorne mentioned, we just – we had a very good quarter with respect to downtime, and cost control.

So just to be safe, we’re going to call for another quarter of being roughly flattish on margin, if not down 200, 300, 400 a day, just from the influence of having a full quarter of rigs, of the 14 rigs working in West Texas at a lower average margin.

Day rates are firm. They’re definitely not going down. If anything, they’re continuing to strengthen slightly. So it is not a result of day rates. And with respect to new builds, we continue to market aggressively on new builds opportunities.

We’ve got a number of different conversations going on in all of our core markets. I would say that we are optimistic that we’ll have some success there and announce you to more new builds. But at this point I don’t have anything to announce.

With respect to the production services business, we think that we will have some unit growth, average unit growth I would say in the fourth quarter which will be positive and cause revenues and margin to go up a little bit. But that will be also offset by our normal fourth quarter seasonality of holidays, vacations. And – so we’re just going to call roughly flat for revenues and margins in our fourth quarter as compared to the third quarter.

That concludes our prepared remarks, we would be happy to entertain any questions. Thank you.

Question-and-Answer Session

Operator

Thank you, sir. Ladies and gentlemen, we will now begin the question and answer session. (Operator Instructions) And our first question comes from the line of John Daniel with Simmons & Co. Go ahead please.

John Daniel – Simmons & Co

Guys, good quarter in a very good color on the operations, so thank you. On the Well Service rigs, the 16 you’ve got coming next year, can you say where you intend to send those rigs?

Stacy Locke

Those would be spread out probably amongst our core operating areas. They’re probably about two-thirds, 550 horsepower, about one-third 600 horsepower. So they will be spread amongst the Eagle Ford, other parts of East Texas, Louisiana possibly, certainly the Balkan. So we’ll be spreading those around all our core areas.

John Daniel – Simmons & Co

On Colombia, this contracts make a lot of income due in the next 8 to 9 months. Are you in discussions yet with renewing the contract? Can you just give us a sense best guess as to what happens with respect to pricing on those rigs when they rollover?

Stacy Locke

Well, we stay in constant – since we have seven of the eight rigs working for Ecopetrol. We are in constant communication with them. In fact, I was just down there last week and met with them, and so we keep an ongoing dialogue and we do expect the rigs to stay active in Colombia. The market is – it continues to be strong and I think the trend would be towards a favorable day rate movement upon renewal and so we’re optimistic about that market. It seems very solid.

John Daniel – Simmons & Co

Right, okay. Last one for me, is just on the well servicing going back there, can you say how many of the rigs are 24 hour versus daylight, and what the expectation would be going forward for more work on a 24-hour basis?

Stacy Locke

John, I would say that right now, what I’m noticing is anywhere from two or six or eight even going in at a time. It just varies depending on activity. But I would say on average, we would expect probably three or four to be on 24-hour work pretty steadily going forward. It just varies goes up and down. But we’re certainly doing a steady amount of it.

John Daniel – Simmons & Co

All right. Okay. Thank you again, and good quarter.

Stacy Locke

Thank you.

Operator

Thank you. Our next question comes from the line of Brian Uhlmer with Global Hunter. Go ahead please.

Brian Uhlmer – Global Hunter

Hey. Thank you, good morning guys. How are you all doing?

Stacy Locke

Great. Good morning.

Brian Uhlmer – Global Hunter

Just following up on John’s question, just curious in both segments now day rates are just may be creeping up and drilling and utilization an all-time high with the labor constraints that most folks are having in the industry. Obviously you have shown to have a better footprint than a lot of guys. How do you guys look at managing labor issues moving forward and controlling your margins and not being able to grave?

Lorne Phillips

Well that’s a great question. We work very, very hard at it. In these businesses, labor is the single most important asset you’ve got, and we try to treat our people well and have good benefits, training, retirement, 401k, and mostly just treat them with respect, treat them right and try to keep them very, very safe and it’s been very effective for us and they appreciate those things.

So I think that’s helping us be able to staff our equipment as we put it out. I’m not going to say that they are waiting at the door, but we have not been held up by the inability to attract group. So I think we just, we’ve got an excellent management team really in all of these businesses. They care about the people and so we are able to get them but we have to work at it.

Brian Uhlmer – Global Hunter

What you guys see as a cost inflation on wages moving forward? Maybe now that we are talking about an extra 5% year-over-year 7%, 8%? How do you guys look at that when you look for at 2012?

Lorne Phillips

Well a couple things on that Brian, it’s going to vary by region as you know. I would say my initial thought would be 5% to 10% as we are looking at budgeting, but a lot of that in increase but remember that the vast majority of that get passed on in contracts under term on the drilling side, and on the production services site, it’s pretty dynamic pricing, so I would not say it’s immediate that costs go up, you immediately pass it on pricing but you certainly work to pass it on as quickly as you can but it’s going to vary a lot by each location. But there is pressure, and there will be increases, but we feel like we should be able to pass that on as it goes on next year.

Stacy Locke

Yeah. We would forecast margin improvement. If what we’re seeing today continues through next year, we think we will see margin expansion in our businesses.

Brian Uhlmer – Global Hunter

Outstanding. And then, on my follow-up, you’ve got pretty detailed strategy of what’s goal and what you have here, and that looks great. Are there any other service lines that have you interested right now or just – for 12 or just follow the strategy laid out – that you laid out with your new rigs and new railcars and new wireline?

Stacy Locke

Well, as we’ve talked about in prior calls, we’re always looking for and evaluating other business lines that we think fit strategically with our core offering. And we continue to do that. And it’s been – there have been a lot of M&A. opportunities come over the last six months I would say.

We’ve seen quite an increase and we’re evaluating a number of those. And it certainly wouldn’t be surprised to see us enter into another business line in 2012 at all. But we just have to find the right management team. That’s really what we look for more than the business is who is going to run it for us? And if they are good and we can build on it, then that’s where we’ll hone in.

Brian Uhlmer – Global Hunter

All right. Thank you, guys.

Stacy Locke

Thank you.

Operator

Think you. And our next question comes from the line of John Keller with Stephens Incorporated. Go ahead please.

John Keller – Stephens Incorporated

Hey. Good morning, guys.

Stacy Locke

Good morning.

Lorne Phillips

Good morning.

John Keller – Stephens Incorporated

I just wanted to drill down the Permian fleet a little bit. 14 rigs there now, going to 16 it sound like and maybe more. But what’s kind of the cadence, or how did those roll off contract into next year? And what do you see in terms of repricing opportunities for those as you sit here today?

Stacy Locke

Well, the first batch of rigs, I would say, the first – remember the first four, I think it was the first four rigs were on six-month terms. And then the subsequent group of rigs were mostly on one-year term. So we have been renewing the earlier rigs already. I think I’ve mentioned in the last quarter call a couple of those contracts, we went up pretty significantly over 1,500 a day, and went from six-month to one-year term.

A couple of the other ones we’ve renewed, they were already top – they were actually top drive rigs. They were already at pretty healthy rates. We’ve renewed those as well at those rates. So most of the roll over will occur in the second and third quarter of next year.

But it’s still a strong market, and we are marketing aggressively there, and we’re pretty optimistic we will have two more rigs there by the end of the year and we are marketing additional equipment there. So it’s continues to be a strong market and we are very pleased with what we see.

John Keller – Stephens Incorporated

Great. And if I could just jump over the well service side for a minute. Clearly, it sounds like pretty positive commentary there notwithstanding normal seasonality. So, do you think that margins could get back up and toward that 50% range that you guys saw say, at the peak?

Stacy Locke

Well, barring no great decline in oil prices, I think that that’s the direction we are heading. If we ever were to give some assistance from natural gas that would certainly help as well. But that may not be a 2012 event. But I think if commodity prices for oil in particular stay strong, the demand as the rig count goes up and more well boars are drilled in all of these shale plays, it’s simply requires not only completion work, but it’s going to require work-over-work and servicing.

So we think that demand just going to steadily go up and we’re trying to prepare for that and have a nice market share in these key markets for us. So we are still very optimistic, we think directionally that’s where it’s heading and if natural gas price comes back at some point, maybe 2013 or 2014, we think we could possibly exceed those margins.

John Keller – Stephens Incorporated

Sure. And then one more if I could just maybe get you to elaborate on, you mentioned the acquisition of well service on the wireline side taking into new basins. Can you tell us where those are?

Stacy Locke

I would rather not. We’re just, you kind of know where we are and you probably know where we are not and you probably know where we would like to be. So I don’t need to be – but we would rather not invite competition into these markets as we develop there. So – but we are moving into markets that we feel like are in their initial stages of development where we see good long-term potential.

John Keller – Stephens Incorporated

Fair enough. Thanks. That’s it for me, guys.

Operator

Thank you. Our next question comes from the line of Roger Read with Morgan Keegan. Go ahead, please.

Roger Read – Morgan Keegan

Morning.

Stacy Locke

Morning.

Roger Read – Morgan Keegan

Just a quick question, I guess for you. You’ve got three more rigs ordered this quarter I understand you can get to back up to 73 by the end of next year. But, at what point and given the lead time for ordering is the rigs fleet for 2012 essentially set? And assuming there is not a CapEx issue limiting what you want to do?

Lorne Phillips

Roger, I would say that we are pretty close to where we will be for 2012. We have a number of conversations going on about additional new bills. But the lead times, as you know, our practice has been when the contract is signed, that’s when we start ordering equipment. And the backlogs on a number of key items have stretched out a bit. And so now that we are coming into the kind of holiday season part of the year, I think it’s unlikely we will execute some term here real soon that will put a bunch more rigs into the fourth quarter of next year. It’s possible, but I would say that we are probably lining up more for 2013 deliveries at this point just due to the lead times. Would you agree with that, Don or...

Donald Lacombe

Yes.

Roger Read – Morgan Keegan

Okay. And then the other question I had was, I understood the amount of the rig fleet that’s on term contracts is roughly 70% level, but if you were to say what is the average amount of months length that you have contracted, is that six months, nine months, 18, if you blended across that 7%, what would that be today?

Stacy Locke

It’s seven month in the US, Roger, and eight months overall when you include Columbia.

Roger Read – Morgan Keegan

Okay. That’s all I have.

Stacy Locke

As per the rigs on term contracts.

Roger Read – Morgan Keegan

Right.

Stacy Locke

And as the new bills come on, and those are all – they are averaging three years I would say as a group for the nine.

Roger Read – Morgan Keegan

Okay, thank you.

Stacy Locke

Thank you.

Operator

(Operator Instructions) And our next question comes from the line of Marshall Adkins with Raymond James. Go ahead please.

Marshall Adkins – Raymond James

Good morning, guys. I just want to get a little more detail on the production services side. I mean, obviously that was a huge quarter, things were improving dramatically there. Walk me through in a little more detail, if you would, exactly where you see the biggest bump there? I mean is it work-over rigs going to do completions now rather than other stuff, is wireline leading it, give us a little more color on that side of the business and why it’s improving so much more right now?

Stacy Locke

Well, on the well servicing side, as you can see, we have been running very high, study utilization for some time now with average hourly rates increasing some of that to offset labor, but we are having gradual margin expansion in that business. So, that has been – that’s just a very steady driver of the overall production service business, and as one of the fellows asked earlier, there is a component of 24-hour work in their which helps tremendous.

Take one of those well service rigs and you work in 24 hours, that’s like looking through 3.5 more rigs. So it’s a huge benefit and we believe that’s going to continue. And then on the wireline front, and that before we leave the well servicing, probably we are still doing today more maintenance work and work over work than we are completion work out of that entire fleet.

A lot of the newer units have been going more into completion mode say in the Eagle Ford or Bakken or wherever, but we are still doing the majority of the work is work-over type work, not completion work. So that’s nice and stabilizing to us.

On the wireline, that is also true. We are – a lot of the growth just like in well services has been to target the completion work and those are the big tickets the higher margin projects, and that’s where a lot of our growth has gone but we continue to have a very nice compliment of business both case hole and open hole in the areas that are not drilling horizontal wells and that’s steady. So I would say the increase is probably more from the completion side over most of this year but it’s just very good, steady growth with more rigs being put to work.

Marshall Adkins – Raymond James

So it sound like the industry has finally gotten into the threshold where you’re bumping up against full capacity and it also seems to me like you are not losing a lot more share to coal tubing like you might have been doing six months or year ago. Is that fair?

Stacy Locke

Well I think the coil is still active. I think the market is just – we are just expanding the overall base market just due to increased rig count, more well bores to be serviced, more completion work. So I think everybody is probably increasing relative to one another. I know coil is still very active and we compete with it daily and they are trying new applications there and so I think it’s probably growing as well.

Marshall Adkins – Raymond James

Okay. All right. Shifting gears to the rig site, can you give me just kind of a quick overview of the type of rigs you’re building? Who’s equipment you’re using, what kind of terms are you getting and what are these things costing you on a fully diluted basis?

Stacy Locke

The contract lengths, we have a couple on the short end in the two-year range, we have some on the four year range, but the vast majority are three-year term contracts. And so the average would be a three-year, not slightly more than that. But – so they’re good, solid term contracts.

The rigs are – well, we have a – we’re basically designing them and Red West is in here with me. Red and the engineering department are designing them and we’re sourcing out like we’ve done in the past, from a number of vendors. I would say that there is a bigger vendor in the mix.

We’re using NOV for the VFD, Hal, the system operating system, the top drive, I think the drawworks.

Lorne Phillips

Drawworks.

Stacy Locke

Drawworks as well.

Lorne Phillips

Iron roughnecks

Stacy Locke

Iron roughnecks. So they have a – I would say maybe a-third of the cost of it. Yeah. Somewhere in that range. So they’re a big vendor. Then we have some fabricators that are doing packages of the rate for us, like all of the backyard. Wouldn’t that be a fair. Yeah. They’re bidding the whole backyard which would include generator houses, mud tanks, pump packages. We tell them what we want and they bid it out that way and they kind of subcontracted that piece of it.

And then we have different vendors designing and building the mass and sub. And then we just coordinate all of that and we coordinate the rig up in one of these yards, and put it all together like Red has done in the past. Basically, what we were doing in ‘04, ‘05, ‘06 as well, same process.

The big difference, I would say now versus then is, we’ve expanded and created an engineering department where we’ve had a three member engineering team and that’s helped. We’ve got bigger rigs, got a lot more things to do. So that helps those guys keep their eye on the ball on the manufacturing.

With respect to the cost, I would say they range depending on which market – they’re all – they all have walking systems, true walking systems, not skidding systems. All the 1,500 horsepower, have 2,000 horsepower lateral mud pump packages with 7,500 psi fluid in and mud systems. So they’re extremely high-end. All of them have integrated 500 ton top drives, automatic catwalks, iron roughnecks, blowup inventors, handling systems, all nine of them all the designs are crane free.

That’s the tweak, I would say from our 50 series. It’s got a little different BOP handling system and we’ve adapted the sub to be truly crane free. The other 50 series rigs were could be done without cranes but these are, you can do it on a routine basis pretty effectively without cranes. Not to say the operator won’t prefer user crane or rig up but because it does again in many cases, make it faster, but the big difference they are all Pat drilling capable. Any other tweaks you can think of that are?

Lorne Phillips

That’s pretty well covered.

Marshall Adkins – Raymond James

And all in cost maybe 18 million-ish.

Lorne Phillips

No, I don’t know where anybody comes up with 18 million. I will just tell you the way out the door, these will cost 21 to 23 million depending on winterization and location. Now and that’s drill pipe. That’s top drive, winterized, for those that were winterized, that tax, that handling tools, all of your tubulars, that’s a working rate. I don’t think people, everyone – everybody throws out that same 18 million number and I have asked a couple to explain that and I still haven’t got a clear answer on it. But I just don’t think tax file and license in the field working with everything needed to do the job, anybody’s doing it for that price.

Marshall Adkins – Raymond James

Well that is a great overview, I appreciate it guys, thanks.

Stacy Locke

You bet.

Operator

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

Stacy Locke

Right. I will add one closing statement relating to the last question about the cost of these rigs, even if that costs at the day rates were obtaining, were generating our target 20% internal rate of return, so full and loaded cost with the day rates that we’re obtaining, we’re hitting our target of 20% internal rate of return. So that’s our real criteria for making that decision. Anyway, that concludes our call. We appreciate everybody participating and look forward to visiting on the fourth quarter call. Thank you very much.

Operator

Ladies and gentlemen, this concludes the Pioneer Drilling Third-Quarter 2011 Earnings Conference Call. Instructions for replay can be found in today’s press release. You may now disconnect and thank you for using ACT Conferencing.

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