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Executives

Lisa Elliott – DRG&E Senior Vice President

Stacy Locke – President, Chief Executive Officer & Director

Franklin C. West – Executive Vice President & President Drilling Services Division

Joseph Brooks Eustace – Executive Vice President and President Production Services Division

Loren E. Phillips – Chief Financial Officer, Principal Financial Officer & Executive Vice President

Analysts

James M. Rollyson – Raymond James & Associates, Inc.

Mike Urban – Deutsche Bank

Steve Ferazani – Sidoti & Company, LLC

J. Michael Drickamer – Morgan Keegan

Judson E. Bailey – Jefferies & Company

[David Deckholm – UBS]

Mark Brown – Pritchard Capital Partners

[Doug Hindig – Keeley Asset Management]

[Mike Trainer] – Milwaukee Private Wealth Management

Michael Mazar – BMO Capital Markets

Pioneer Drilling Company (PDC) Q4 2008 Earnings Call February 26, 2009 2:00 PM ET

Operator

Welcome to the Pioneer Drilling fourth quarter earnings conference call. During today’s presentation all parties will be in a listen only mode. Following the presentation the conference will be opened for questions. (Operator Instructions) This conference is being recorded today, Thursday, February 26, 2009. I would now like to turn the conference over to Lisa Elliott, Senior Vice President of DRG&E.

Lisa Elliott

We appreciate you joining us for Pioneer Drilling’s conference call to review its fourth quarter and full year results. Before I turn the call over to management, I’d like to review a few things. In a few hours a replay of today’s call will be available and it can be accessed via webcast by going to the company’s website, that is www.PioneerDRLG.com, where it will be archived for one year in the investor relations section and also via telephonic replay through March 5 by dialing 303-590-3000 and entering the pass code 11125734.

You’ll also find that information in today’s press release. Information recorded on this call speaks only as of today, February 26, 2009 and therefore time sensitive information may no longer be accurate as of the date of any replay. Today management may make forward looking statements which are based on management’s belief as well as assumptions by and information currently available to management.

Although management believes that the expectations reflected in such forward-looking statements are reasonable they can give no assurance that such expectations will prove to be correct. Such statements are subject to certain risks, uncertainties and assumptions which are described in this morning’s earnings release as well as the company’s most recent annual report on Form 10K and subsequent filings with the Securities & Exchange Commission.

Should one or more of these risks materialize or should the underlying assumptions prove incorrect then actual results may vary materially from those expected. Please also note that this conference call may contain references to non-GAAP financial measures which you can find the reconciliation of these non-GAAP financial measures to GAAP financial measures in the Form 8K filed by the company earlier today as well as in this morning’s press release.

Now, I’d like to turn the call over to Mr. Stacy Locke, President and Chief Executive Officer of Pioneer Drilling.

Stacy Locke

Joining me on the call this afternoon is Red West, President of our Land Drilling Division, Joe Eustace, President of our Production Services Division and Loren Phillips, our new Chief Financial Officer. Loren had a strong analytical mind, he’s a good strategic thinker and he brings operational experience to the table in addition to a good strong finance and accounting background and we’re very, very happy to have him join our team.

Stepping back for a second and looking at kind of the big picture for 2008 we had a great year for Pioneer. We drove revenues up 47% to $611 million, we drove EBITDA up 48% to $214 million and we drove diluted earnings per share up 30% to $1.47 excluding the non-cash charges. It was a year of diversification for Pioneer, we successfully diversified our business where today roughly 30% of our revenues come from the production services segment.

We successfully reached our five rig run rate in our first international market in Columbia. And, we also decreased our exposure to natural gas where today we’re approaching a 20% mix of oil related business. We believe that this growth in high quality assets and people and the diversification is a good strategic direction for the company in the long term. I would like to go ahead and turn the call over to Loren to review some financials and then I’ll make some follow up comments.

Loren E. Phillips

I’d like to cover three areas this morning: a quick run through of financial highlights and unusual items; our expectations for expense trends going forward; and our liquidity position at yearend and capital plans for 2009. As we reported this morning, for the fourth quarter of 2008 we had a net loss of $117.9 million or $2.37 per diluted share. The loss was attributable to three items, the first is $118.6 million write off of goodwill recorded in connection with our acquisitions last year of the WEDGE Companies, Competition Wireline and two smaller production service companies [Petis] and [Paultech].

The second related item is a $52.8 million impairment charge relating to the carrying value of intangible assets also recorded in connection with the production services division acquisitions. If you exclude the impact of these two items we would have had net income of $18.7 million or $0.37 a share. That is $0.10 higher than the prior year’s quarter and up $0.09 from the third quarter. The impairment charges were necessary due to the overall downturn in our industry beginning in the fourth quarter 2008 which resulted in a decline in our market capitalization and downward revisions to the estimated future cash flows for these operations.

The third and much smaller item relative to the prior two is an increase of $1.35 million for the allowance of doubtful accounts during the fourth quarter. This charge was related to one customer for the US drilling business. EBITDA in the fourth quarter was $60.4 million. That’s an increase of 72% from a year ago and reflects the addition of production services. Sequentially EBITDA is down 6.6% from the third quarter.

Drilling revenues were $123.3 million which is up approximately 18% from a year ago and down slightly from the September quarter. Almost $18 million of the revenue came from our Columbia activities. Production services revenues were off by 5% sequentially to $47.4 million due to declining activity and traditional down time during the holiday weeks in November and December.

Moving on to some of the expense items, depreciation and amortization was higher than in the third quarter due to the culmination of additional equipment in production services and the higher number of rigs in our fleet. The much larger jump in D&A year-over-year reflects the addition of the wells services assets. The intangibles impairment will reduce amortization from $8.4 million in 2008 to $4.5 million for 2009. Overall, we expect approximately $105 to $110 million in D&A for 2009.

Selling, general and administrative costs were down for the third quarter due mainly to lower legal and professional fees related to the now completed accounting practices investigation and to related compensation expense. For 2009 we have already and will continue to cut costs across the company and we expect approximately $45 to $47 million in SG&A costs for the year. Interest expense was $3.5 million in the quarter which was about $300,000 lower than in the third quarter due primarily to lower interest rates.

Now, looking at our capital and liquidity position; at December 31st we had cash and cash equivalents of $26.8 million up from $17.3 million at the end of the third quarter. We currently have $257.5 million borrowed against a $400 million line of credit that we took out to finance the production services acquisitions a year ago. That amount is down from $272.5 million a year end. Our plan for 2009 is to further reduce debt using cash flow from operations.

Our total debt to total capital ratio at the end of the year was 40.3%. This is higher than at September 30th again, due to the impairments. The impairment charges are not expected to have an impact on our liquidity or debt covenants. Cap ex is one area where we’ll obviously be more conservative in 2009. Capital outlays in 2008 excluding $350 worth of acquisitions last year totaled $147 million.

In 2009 the approved cap ex budget is $65 million, $50 million for drilling services and $15 million for production services. In addition, we have approximately $19 million of committed or planned capital expenditures at December 31, 2008 that will be funded in 2009 bringing the total to $84.5 million. We also expect to fund these expenditures from operating cash flow.

Despite the continuing difficulties in the credit markets, our balance sheet is solid and while we know current market conditions are going to impact our cash flow in 2009 we’re making every effort to adjust our business accordingly and bring our cost in to line with expected revenues. With that, I’ll turn it back over to Stacy.

Stacy Locke

I’d like to review a little bit more detail kind of our status on equipment and our capital expenditures. At the current time we have 70 land drilling rigs five of which are in Columbia and only one planned addition for 2009. That’s the second 1,500 horsepower electric rig that was approved under last year’s budget that will be delivering to Williston North Dakota in late March and that will begin operating probably in April under a three year term contract.

Switching to the production services side we currently have 74 work over rigs in our fleet. 12 of those rigs are currently stacked without crews, the others we are marketing. We have no planned additions for 2009 for work over units. The wireline fleet at 59 count today, we do plan to add two additional wirelined units in the first half of 2009. Fishing and rentals has approximately $15 million of equipment available and we’ll have $.5 million increase for fishing and rentals in 2009.

As Loren stated we cut our approved AFE base capital budget 63% from the $176 million capital budget that we had in 2008 down to $65 million. Of that $65 million about 37% of that is routine capital expenditures just to keep the equipment in good shape and [inaudible]. The remainder over the 11% which is for the new build related new equipment expenditures is discretionary items that will help market our drilling fleet primarily. This would include five top drives, three iron roughnecks, four 1,600 horsepower pump packages and two automatic catwalks and perhaps a little bit of other equipment. If the market continues to deteriorate we might further reduce that discretionary piece of the capital budget.

With respect to our term contract coverage, a little over 90 days ago on our Q3 call in the United States we had 28 term contracts. Today we have 21. We have three rolling off in the current quarter, Q1, we’ll have seven more in Q2, six in Q3 and two more in Q4 leaving us three term contracts for 2010. Of the days in ’09 that are protected we have 18% of ’09 days protected 90 days ago now, we’re down to 15%.

As these term contracts roll off in Q1 and Q2 we would expect an order of magnitude adjustment on average day rate from about a $20,000 a day level down to somewhere on average of a $13,000 a day level which would be approximately a 35% reduction. In Columbia, we had five rigs loosely defined as term contracts. Today we really only have one working under term contract. Having said that, we anticipate that we will continue to work three to four, possibly all five rigs with our primary customer for the remainder of the year but at this point that’s still undetermined and uncertain. But, for certain it will be at reduced day rates.

A little more specificity on the forward day rates, in the last quarterly call we gave a range for the 750 horsepower to 1,500 horsepower class without top drive and without fuels we provided a range of about $16,000 to $20,000. On average, these rates have come down at least 30% to more of a forward range today of $11,000 to $14,000. So, it’s been a very drastic decline.

That concludes our prepared remarks. We’d like to open it up to questions at this time.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from James M. Rollyson – Raymond James & Associates, Inc.

James M. Rollyson – Raymond James & Associates, Inc.

You gave us great detail on your view of the day rate side of the equation and kind of what’s happened. Could you maybe give us your thoughts on the cost side? Typically as I’ve watched this business you tend to see your unit costs go up a little as your rig count is falling at first and then as you’re implementing cost reductions that kind of settles out and maybe starts coming down. How are you thinking about that as you go through 2009?

Stacy Locke

Well, unfortunately I guess what we report in the press release is average revenues per day and average cost per day so that includes a little more noise than just a pure day rate and a pure cost per day day rate cost. I guess the cleanest answer would be that I think our average day work cost associated with those day rates has probably been running close to $10,000 per day. I think going forward we feel like we’ll be able to reduce that pure day rate cost down. With the one wage reduction we have in place we think we can reduce that down to $9,000 to $9,500 a day.

Now, when you look at what’s reported in this press release you get a lot more noise that’s in there so you won’t get that clean of a number when the press release comes out but that’s what we believe will kind of be our rough estimates.

James M. Rollyson – Raymond James & Associates, Inc.

Do you think that happens in the first quarter or over the next couple of quarters?

Stacy Locke

Well, we put in a wage decrease at the beginning of February so I think from that pure number we’ll see the impact of that wage decrease in this current quarter. Now, it’s going to be a little masked because like if you noticed in the press release on page eight where it talks about the drilling revenues per day and the drilling costs per day you have a lot of things built besides mobilization just rig job to rig job kind of muddying up the water there are two big mobilizations of the two rigs that went in to Columbia in the middle of the year and one as late as November.

That costs to move the rig to Columbia is amortized over the term. Let me say it easier, we’ll be through amortizing that mob cost which is a revenue and a cost, we’ll complete that in this quarter. So, those types of things will muddy it up. Then of course, we had a wage increase that kind of hit at Q3 at the end and then it was present in Q4. That will be backed out in Q1. You have quite a few moving parts there but I think we will see of the raw day rate cost we’ll see that taking place this quarter and then we’ll see the full impact of it in the second quarter and then by then a lot of this noise I’m discussing will fall out as well.

And, I think it’s a fair likelihood that as we move through the course of the year in the market that we’re in as other drilling contractors catch up with our utilization we’re going to see an additional wage decrease.

Operator

Your next question comes from Mike Urban – Deutsche Bank.

Mike Urban – Deutsche Bank

A couple of your competitors have addressed attempts by customers to either renegotiate or cancel contracts and some of them have received some lump sum payments or similar to that. I guess the first question would be one, have you seen any of that? And, then what do your contracts have in terms of provisions and can we expect to see something similar in terms of lump sum payments?

Stacy Locke

I think with respect to our 21 term contracts I don’t see anything or we’re not really having any discussions that would put those contracts at risk being terminated or renegotiated downward. However, right now we have one term that is being paid and the rig is not working. We have another customer that has three rigs that has discussed potentially stacking out but continuing to pay on two of the three. That’s kind of where we are. I think our contracts are good. I think they’re solid on the two new build rigs. As far as we know those contracts should continue.

Mike Urban – Deutsche Bank

Just to be clear, it doesn’t sound like you are necessarily having those discussion but if someone came to you and said, “We want to terminate a contract.” Do your contracts have provisions for some sort of protection for you?

Stacy Locke

Right. Every contract we have requires them to make some sort of payment through the end of the term of the contract to protect Pioneer.

Operator

Your next question comes from Steve Ferazani – Sidoti & Company, LLC.

Steve Ferazani – Sidoti & Company, LLC

What’s the process in terms of when you decide to stack another rig or cut back on crews? And, how many full crewed rigs that you still have that probably don’t have a lot of work out there?

Stacy Locke

Well, let me distinguish between kind of a cold stacked rig and a stack just an idle rig. We have five rigs that are cold stack in our Western Oklahoma division, in Woodward where those rigs have been stacked out, pickled as we call it in the industry and all the crews and related expenses are off of those rigs. On rigs such as South Texas that has been hit pretty hard, we have idle rigs if a rig goes down and we don’t have a near term opportunity to put it back to work and by near term I mean literally in a week or so then we eliminate the crews on that rig.

So, as we mentioned in the press release we’ve released about 37% of our work force. We just can’t continue to pay the labor on rigs that have an uncertain work future so we’ve just had to cut them loose.

Steve Ferazani – Sidoti & Company, LLC

In terms of your average revenue per day for modeling purposes I’m assuming it’s more of the lower horsepower rigs that aren’t working so that will come down but not necessarily as quickly because it’s the higher horsepower rigs that remain under contract. Is that a fair assessment?

Stacy Locke

Not really. As we mentioned in that press release we have rigs of all rig classes that have been released. I would say that it’s Western Oklahoma which are our absolute lowest horsepower, 600 to 700 horsepower rigs or even 500 to 700 horsepower rigs, that market evaporated back kind of in the late summer early fall and so that’s why we cold stacked those rigs. But, of the remaining fleet that are lower horsepower range rigs would be 750 to 900, we have quite a few of those down but then we have some 1,500 horsepower rigs down and 1,000 horsepower as well.

It’s kind of across the board and it’s across all geographic regions. But, I guess to answer your question, there’s no doubt that average revenues per day will be declining probably each quarter through this year as day rates are under pressure and we roll these term contracts over.

Operator

Your next question comes from J. Michael Drickamer – Morgan Keegan.

J. Michael Drickamer – Morgan Keegan

Stacy, historically when the industry is a little bit softer you guys try to offset it by driving more turnkey work or footage contracts, have you guys started increasing that yet?

Stacy Locke

We have been eager to do more turnkey contracts. Through the fourth quarter we’ve averaged roughly two turnkeys per quarter. So far this quarter I think we’re on our first. We’re doing one right now. I don’t know, we may have two this quarter but we would hope that some of the turnkey would be on the increase. We like to do that during slow times because we can improve our average margins per day in areas where we are experiencing and drilling the turnkeys. I think it will increase a little bit but we’re still uncertain on the outlook for that.

J. Michael Drickamer – Morgan Keegan

If you think that the turnkey does increase do you expect that to have a material impact in your average reported revenue and operating cost?

Stacy Locke

Yes, as we talked about in the past, all of that additional expense of casing, mud, bits, cement, casing crews, all of that goes both through the revenue line and the cost line and hopefully our margins widen in that process. So, that causes your average revenues per day and average cost per day to go up. But, hopefully if you’re doing that you’re also offsetting some of the day rate decline in margin.

J. Michael Drickamer – Morgan Keegan

Then geographically you talked about a couple of markets already with South Texas and Western Oklahoma but, where are you seeing the greatest weaknesses in your fleet as far as your most idle rigs.

Stacy Locke

I think the easiest place to start would be where are we seeing more strength. The only area that we’re seeing some strength is East Texas and fortunately that’s where we have the biggest concentration of rigs. I guess the big surprise for us all is South Texas because historically that has been a pretty solid market and it has been hit extremely hard in this particular cycle.

I think that we’re fairly confident that we’re going to work our utilization back up in that market but the one that has held up more so than any other region has been East Texas and really every other market has been hit hard. I guess Columbia has been a big surprise to us as well. We were crowing a little bit on that last call about how pleased we were with everything there and it had done outstanding and we ended up the year there in great shape, it met all of our expectations but, as the US market continued to deteriorate those folks in Columbia are pretty plugged in on what’s going on in the US and a lot of our competitors expressed more interest in Columbia and it caused a total rethinking, repricing of that market from the perspective of the operators.

Of course it’s oil driven there and that price was in the $30s gave them the ability to do that. So, I think that market will strengthen back up again as oil prices firm up but for right now it’s really no better than the US market.

Operator

Your next question comes from Judson E. Bailey – Jefferies & Company.

Judson E. Bailey – Jefferies & Company

Stacy I wanted to follow up on the discussion on your average day work cost and the average day rate you mentioned. I just wanted to clarify when you mentioned was it average day rate you said was around $20,000 and you expect that to decline 35% or so?

Stacy Locke

In the third quarter call a little over 90 days ago I gave a range for 750 horsepower up to 1,500 horsepower without top drives, without fuel of $16,000 to $20,000 and what I’m saying now is that range would be $11,000 to $14,000. If you put a top drive on it you might be up $15,500 to $16,000 a day. But, for a 1,500 without a top drive is probably in the range of $14,000 plus or minus a little bit.

Judson E. Bailey – Jefferies & Company

On your rig time sell, you gave some pretty good numbers on how many term contracts you have rolling off. Do you have any visibility of how much more downsize you may have to your rig count from the current level of 34 over the next four or five months?

Stacy Locke

As you know going back in the history of the company through many cycles historically we’ve done well on holding our utilization up. We are being impacted this time because we choose to go pursue the production services area and we discontinued building new and so our term exposure has gradually gone down so we’re a little more vulnerable to rapid market fluctuations like we’re experiencing.

So, we have taken it on the chin quickly. I think and I believe that Red thinks from the drilling perspective, and I think it’s probably true on the production services too, I feel like we believe we’re going to be able to fight along here pretty good at these levels and try to keep our utilization and we’ll try to get the highest day rate we can possibly get. There’s no certainty to that but I feel like plus or minus 5% we should be able to hold in here. Red, do you have anything you want to add to that?

Franklin C. West

I feel the same way. I don’t see much more downside. I think we can get some rigs back to work.

Stacy Locke

We’ve got rigs going back to work and we’ve got some coming down. I think we also believe that towards the end of the year our customers are going to start drilling again. The drilling cost has come down very, very rapidly, the other costs are coming down now fairly rapidly. I think by the summer the cost to drill a well is going to be considerably below what it was last year at the same time so with the rig count coming down then I think there’s going to be some hope that we put the gas market back in balance and the strip will strengthen a little bit and with the low cost people will start drilling again. That’s kind of what we hope will happen.

Judson E. Bailey – Jefferies & Company

One more if I may, could you quantify of the rigs you have currently that are idle right now how many of those are either 1,000 or 1,500 horsepower rigs?

Stacy Locke

Red is estimating about half and half and I think he’s probably pretty close. We have the five lower horsepower rigs flat cold stacked so we have a fair number of 750s stacked and we have a lot kind of in the 1,000 horsepower range stacked. So, they’re a little bit across the board.

Judson E. Bailey – Jefferies & Company

So it’s fairly evenly distributed then of the ones you’ve got idle, is that fair to say?

Franklin C. West

Yes. I think our very best top of the line, state of the art rig that competes with any rig in the business out there is at risk just like a 1,000 horsepower would be.

Operator

Your next question comes from [David Deckholm – UBS].

[David Deckholm – UBS]

I’ve just got a quick question for you here, on the Columbia side I understand that day rates are coming down about the same magnitude as the US. Do you still expect that premium then of about 30% on the day rate side to be maintained in Columbia versus the US?

Stacy Locke

Well, I think the average day rate reduction there is actually a little less than what we’re experiencing. I would say it’s more maybe in the order of 25% decline on average. But, the cost there are higher and we are – I don’t know for sure how we’re going to settle out. I would venture to guess that our average margin will continue to be a little bit higher there than here but that’s with an assumption that we’ll be able to reduce some of the costs as we’ve been able to scale down here in the US. So, we’re still optimistic that it’s going to be a little bit more attractive than the US but we have to kind of prove it to ourselves I think.

[David Deckholm – UBS]

On the work over side, actually on both sides of the business, are there any instances right now where your rigs are being used as [inaudible] complete the wells? Is that eating in to any potential work over business?

Stacy Locke

I don’t think we’ve seen any indication of that at all.

Operator

Your next question comes from Mark Brown – Pritchard Capital Partners.

Mark Brown – Pritchard Capital Partners

I’m just wondering how you see the margins trending for the production services side. Do you expect to see a lag in terms of how quickly you can bring your costs down versus revenues per day coming down?

Stacy Locke

The total production service business Q3 to Q4, we had everything going the wrong direction. We had revenues going down, cost going up, margin as a percentage of total going down from 50% to 45%. Now, that fourth quarter really affects but in particularly the work over business, the well service business from about Thanksgiving on, it’s always a slower period. It’s weak in pretty much every segment of that business currently.

I think we’re seeing signs of some strengthening presently but we’re still not out of the woods and the utilization on the work over side, the utilization has come down. The fourth quarter was down over the third quarter and we’ve come down further since and we’re fighting on our pricing. Our pricing per hour is still higher than everybody else’s but it’s down probably on average 10% to 13%.

So, it’s a struggle and a fight everywhere you turn and I don’t have clarity on how we’re going to see that margin evolve. I think it’s going to be weak for certain in Q1. I think if I had to venture a guess I think it’s going to improve in Q2 and later in the year. I feel like that business is going to probably do what I think we believe is going to happen on the drilling side that we’ve taken it hard quick and we’re going to firm up a little bit as we move later in the year.

Mark Brown – Pritchard Capital Partners

Just on the drilling side, do you have any feel for how many of your rigs might be scrapped coming at the end of the down cycle? Or, maybe how many rigs across the industry do you think will likely be scrapped, some of the older legacy equipment?

Stacy Locke

Well, we don’t have any plans to scrap any of our rigs. As we’ve kind of acknowledged over the years, we’ve invested a lot in to our more traditional fleet. They’ve been modernized with rounded bottom mud tanks and dual linear motion shakers on cleaning the mud and higher newer hydraulic horsepower on the mud pumps and we’ve added iron roughnecks on over 60% of the fleet and we’ve added some top drives.

Our fleet, even though there are some attritional rigs in there it’s still in very, very good condition. Even the low horsepower rigs that are cold stacked in Western Oklahoma have been upgraded materially from what we purchased at the end of 2004. So, it’s good for that market so we really don’t have any plans to scrap anything.

With respect to the rest of the US I think no doubt there’s a number of rigs that will be scrapped out this year. I think one of our competitors announced that they were bringing on 22 new builds and 22 existing rigs. I think that’s going to be pretty common in the fleets of the largest – well, actually some of the smaller ones as well. I think there’s a fair amount of scrap rigs in pretty much most everybody’s fleet out there maybe with one or so exceptions.

Operator

Your next question comes from [Doug Hindig] – Keeley Asset Management.

[Doug Hindig] – Keeley Asset Management

Stacy, could you talk a little bit more about the well servicing business? What the utilization rate is and what your hourly rate is and your cash costs?

Stacy Locke

The utilization declined in the fourth quarter down to 67% from 80% in the prior quarter which had been the top quarter for us in 2008. Our hourly rate actually in Q4 was our highest average hourly rate which was over $600 at $620. Presently, that is kind of down more in the low $500 an hour, $525ish range and the utilization has dropped closer to 50%. It is facing a lot of pressure on hourly rates and has been tough on utilizations.

[Doug Hindig] – Keeley Asset Management

Did I have it right, do these rigs go in to the yard at night or are they around the clock on the well site?

Stacy Locke

We have some that are doing 24 hour jobs. The high hourly rate in Q4 was partially due to the fact that we had several 24 hour jobs working. But, these are for the most part rigs that work daylight hours and shut down on the weekends. Now, they are high end work over rigs. As I mentioned before, they’re all 550 class national 5C for the most part, very, very high quality, high end fleet. The reason that the hourly rate is higher is because we package those rigs with a pump and a mud tank and a BOP going after the deeper gas primarily.

[Doug Hindig] – Keeley Asset Management

So you could actually drill with those?

Stacy Locke

No, they’re not set up to drill with. They’re very different from say a Cabot 750 which is another mobile style carrier mounted rig. Those are designed to drill these are not.

[Doug Hindig] – Keeley Asset Management

Looking back with hindsight which is 20/20, do you regret having made that acquisition or do you think that strategy will still hold out? In other words will the well servicing business hold up enough to kind of give you some [inaudible] on the drilling side? I imagine that was what was your strategy, right?

Stacy Locke

That was the whole purpose of my preamble was to say that I still think it’s a good strategy. I think could we have perhaps done better by continuing to build new rigs and add 10 to 20 three year term contract new builds in the market we’re in right this second? I think we would have been better off having done that in the short run.

But, I think in the long run I still am a big believer that the diversification that the production service offers having both a wirelined segment, fishing and rental and work over long term I think it’s going to be a great concept and I think historically and the reason we did it, is historically it has propped up relative to the drilling in the down markets.

It just so happens that this down market happen to come coincidental with the slowest time in the year for production services which is during kind of the fourth quarter beginning of the new year and so we kind of get a double whammy there. But, I still think it’s going to prove out to be a great combination and so I’m optimistic and I still think it was the right direction and strategy for us.

[Doug Hindig] – Keeley Asset Management

The work tending to be more servicing producing wells, in other words really well servicing rather than completion of new wells and is that what will hold you up?

Joseph Brooks Eustace

I think it always has been more production service work than it has been completions. Completions even in the high point of the upturn was not that much of our business.

Operator

Your next question comes from [Mike Trainer] – Milwaukee Private Wealth Management.

[Mike Trainer] – Milwaukee Private Wealth Management

To clarify the utilization ratio for the press release was [inaudible] did you say plus or minus 5% of that is what you expect your utilization to be going forward on a [inaudible] level?

Stacy Locke

That’s what we think. We think we could get hit a little further on it but we’re feeling like we’re kind of approaching a base line for the company. That’s what we feel like, I’m not saying we can hold that but I’m saying that I think we could go a little bit lower but we’re kind of approaching a point where I think we can keep from going lower than that.

[Mike Trainer] – Milwaukee Private Wealth Management

Does the company operate or would you expect it to operate profitability at this lower utilization rate?

Stacy Locke

Well, I think from a cash flow basis we will continue to generate solid cash flows. I think we’ll still be able to pay down – based on what we know today I think we’ll be able to continue to reduce our indebtedness further with our paired back capital expenditures. But, on the net earnings line I think that is going to be a challenge for this year.

Operator

Your next question comes from Judson E. Bailey – Jefferies & Company.

Judson E. Bailey – Jefferies & Company

Just a quick follow up guys, Stacy how many rigs did you have running at the end of the fourth quarter?

Stacy Locke

You mean how many were working or in the fleet?

Judson E. Bailey – Jefferies & Company

How many active rigs did you have when you ended the quarter? You have 34 today I just wanted to get a sense of how many you had at the end of the December.

Stacy Locke

I don’t know that. I don’t want to mislead you. But, I will just give you a little color on that, we had a number of unanticipated reduction in the month of December that caught us by surprise so that rig count was definitely impacted in December greater than we had anticipated it but I just couldn’t tell you the exact number. So, there was already a pretty good decline taking place in December.

Operator

Your next question comes from Michael Mazar – BMO Capital Markets.

Michael Mazar – BMO Capital Markets

Just a quick question here and I don’t know if you’ve talked about this before, can you mention or walk us through what the relevant covenants are associated with the debt?

Stacy Locke

I think that’s all publically available information so I think Loren would be happy too.

Loren E. Phillips

There are two covenants, one is interest coverage ratio, the other is a total debt to EBITDA ratio and as long as total debt to EBITDA is less than 2.25 and your mean interest coverage ratio which I believe is 3 to 1 then, those are the only two covenants. However, if you go above the total debt to EBITDA at 2.25 then you would need to do what is called an asset coverage ratio test and that involves looking at receivables and the orderly liquidation value of your assets. Then, that would need to be 1.25 of the total commitment of the facility.

I apologize if I’m not explaining this as eloquently as I should. The current covenant through March 31, 2010 would say we need to be below 2.75. If we happen to go above 2.25 we also have the asset coverage ratio test. At this point we have I think at the end of the quarter it was 1.28 to 1 total debt to EBITDA and our interest coverage was over 17 to 1 so we met all those tests.

Michael Mazar – BMO Capital Markets

That’s presumably a backwards looking four quarter test?

Loren E. Phillips

It is, trailing 12 months.

Operator

At this time I’d like to turn the call back over to Mr. Locke for some closing remarks.

Stacy Locke

We appreciate you all joining our call this afternoon. I want just to say that we realize these are tough times in the industry. We feel like we’ve acted fact to cut our cost and downsize with the industry. We’re prepared to continue to do that in case it gets worse. But, we think we’re in good shape and we’ll battle it out here and get to the other side. At any rate, thank you for joining us this afternoon.

Operator

Ladies and gentlemen this concludes the Pioneer Drilling fourth quarter earnings conference call. This conference will be available for replay after 2pm Eastern Standard Time today through March 5th at Midnight. You may access the replay system at any time by dialing 303-599-3000 and entering the access code of 11125734 pound. Thank you for your participation and at this time you may now disconnect.

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