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Executives

Ann Pearson – DRG&E Investor Relations

Stacy Locke – President and CEO

Lorne Phillips – EVP and CFO

Analysts

Judd Bailey – Jefferies & Company

John Daniel – Simmons & Company

Brian Uhlmer – Global Hunter Securities

John Keller – Stephens Inc.

Jim Rollison – Raymond James

Janice Rut – Pritchard Capital

Roger Reed – Morgan Keegan

Mike Kelly – Kennedy Capital

Jeff Kagan [ph] – Milwaukee Private Wealth Management

Pioneer Drilling Company (PDC) Q1 2011 Earnings Call May 5, 2011 11:00 AM ET

Operator

Good morning ladies and gentlemen, thank you for standing by. Welcome to the Pioneer Drilling Q1 2011 Earnings Conference Call. (Operator Instructions). This conference is being recorded today, Thursday May 5th, and I would now like to turn the call over to Ann Pearson with DRG&E Investor Relations. Please go ahead, ma’am.

Ann Pearson

Thank you, Jeremy, and good morning everybody. Before I turn the call over to Stacy and Lorne for their formal remarks I have a few of the usual items we need to cover. First of all, a replay of today’s call will be available and is accessible by webcast by going into the Investor Relations section of Pioneer’s website and also by telephone replay. And you can find all of the replay information you need in this morning’s news release.

A reminder: information reported on this call speaks only to today, May 5th, 2011, so any (interference) and information may no longer be accurate at the time of any replay. Management has no obligation to update any (interference) made today and all assumptions are based on information currently available to us, and while management believes the expectations reflected in these statements are reasonable they can give no assurance they’ll prove to be correct. They are subject to certain risks, uncertainties and assumptions as described in this morning’s release and also in Pioneer’s most recent filings with the SEC. Should one or more of these risks materialize or should (interference) actual results may differ materially.

Also please note that this conference call today contains references to non-GAAP measures and a full reconciliation to the GAAP financial measures is available in this morning’s press release. So now I’d like to turn the call over to Stacy Locke, Pioneer President and CEO. Stacy?

Stacy Locke

Thank you and good morning everyone. Joining us on the call today is Red West, President of our Drilling Services Division and Lorne Phillips, our Chief Financial Officer.

Overall, Q1 was about as we’d expected. Both revenues and EBITDA were up higher than expected quarter-over-quarter, a little over 3%. I’m not going to review many of the financials in my comments, Lorne is going to go over that in just a second, but what I think is exciting about our Q1 and where we are year to date is the achievement of what I would call our critical strategic objectives for 2011 – one is putting stacked rigs back to work, and two is growing our three core businesses in oil and liquid-rich unconventional plays: that’s land drilling, wire line and well services.

With respect to putting stacked rigs back to work, our new West Texas endeavor has exceeded our expectations by threefold and could end up exceeding by fourfold the end of the year. We had budgeted at the beginning of the year to relocate four rigs to West Texas on a timeframe of one in May, one in July, one in September and one in November. We were fortunate, we were received well in West Texas when we began intense bidding in that market at the beginning of the year, and it allowed us to put all four rigs into that market by the end of March. So we were way accelerated on that opportunity.

More importantly, we have now executed an additional nine contracts for rigs that’ll be relocated mostly out of our stacked inventory of rigs in North and East Texas, but we will be relocating one that’s been quasi-active from our South Texas market. We anticipate, we are readying the first three of these rigs currently and we anticipate that we’ll have the first two working in West Texas by June, the second two working there by July, then I’m saying the beginning of June, the beginning of July; two more by the beginning of September and two more by the beginning of November, and one more by the beginning of December. That’s the nine rigs.

Eight of those are under one-year term contracts and one is under a six-month term contract. In addition, we’ve identified another group of rigs that we are marketing there that could possibly make it to the West Texas market also by the end of the year, but we have not secured contracts for those rigs yet. So the expected margins from that operation are somewhere in the $3500 per day to $4500 per day range, so therefore about every three rigs we move out there will approach new build economics or new build margin at about a quarter of the cost. So these are very high rate of return opportunities for the company and we’re excited about that long-term.

In addition of course, if you assume a 69% utilization starting point, which is about where we are today, this will allow us to over these next few quarters bring that utilization rate up over 80%. I’m very, very proud of our team for taking this start-up division from zero to 13 rigs in less than 12 months. It was just a great effort on everybody’s part.

The other strategic objective for the Drilling Services Division is new build rigs. This is a very competitive market as you know, but we have a 1500 horsepower AC design that Red West and our Engineering Department have developed that is receiving considerable interest. It is a true walking rig for PAD drilling applications, not a skidding rig like a lot of the rigs that are being built out there today. So if the trend towards more PAD drilling develops as it has in the Marcellus and is beginning to in the Bakken and just beginning to in the Eagleford, then this rig will be about as efficient as a walking rig as any rig designed in the marketplace.

It also is a rig that rigs up without a crane. It has a number of kind of quick hookup features to make the rig up/rig down quicker, and it has the same integrated-type 500 ton top drive that stays hooked up in the mast and the rig moves like we have on our 50-series rig. And we’re putting 2000 horsepower mud pumps with 7500 psi fluid ends on this new designed rig for greater pressure and more gallons per minute driving the motor and bit. So it has been very well received. We have a number of discussions going on right now, and as the customer that just contracted the one rig said, “I’ve looked at every rig design on the market today and we like your rig design.” So we’re excited about the prospects for that rig and other rig designs that we’re marketing, and we’ve secured our first contract and are beginning the building process on that rig; and that rig we anticipate will be delivered during the Q1 of 2012.

Turning to our Production Service Division, revenues were roughly flat quarter-over-quarter. That was a little better than we expected. Margin was down about 3% to 38% of revenues, roughly as expected and it did contain quite a bit of start-up costs for lots of these new areas that we’ve moved into during the end of last year and this year. In our Wire Line Division we continued to grow at a healthy clip. You’ll recall we grew 33% in unit cap in 2010 and we will grow at another 20% this year, and we’re further penetrating the unconventional oil and liquid-rich plays around the country. We should end up roughly 101 units by the end of this year if we don’t order additional units.

To date we’ve already received 14 of the 17 planned units and are working to ready these in the new markets that we’ve moved into. Pricing is firm and firming up a little bit in certain markets and activity levels look good, however we will experience some lingering start-up expenses as we develop these new markets in the short term. Well Services continue to perform very well and in Q1 utilization was down as we expected although we anticipate utilization will improve in Q2 and as we move through the rest of the year.

In addition, prices did edge up a little bit as we had hoped and we expect pricing to firm up from here through the remainder of the year. After a challenging 2009 and 2010 market for the Well Services Division we are finally back to growing that business. We plan to add four 550 horsepower units and two 600 horsepower, what we call “XL rigs” this year. To date we have received three of the rigs, two 550 horsepower rigs and one 600 XL. The 600 XL is just a little more powerful rig with a taller mast to make the rig a little more suitable for the higher-pressure completion work that we’re doing in the Eagleford and other higher pressure plays. We will likely order some additional 600 XL models later in this year.

Now I’d like to turn the call over to Lorne for an overview of the financials.

Lorne Phillips

Thanks, Stacy, and good morning everyone. We recorded a net loss in Q1 of $0.11 per share. These results were impacted by the non-recurring net worth tax on our Colombian operations that was assessed on January 1st. Again, although it is payable in eight semiannual installments from 2011 through 2014 we recognize the full on deductible tax expense in Q1. Excluding this tax we would have recorded positive earnings of $0.02 per share during Q1; that compares to a net loss of $2.7 million or $0.05 per share in the prior quarter when excluding the negative impact of a $3.3 million charge for the impairment of option rate preferred securities in Q4. Our reported net loss in Q4 was $6 million, or $0.11 per share.

Our total revenue this quarter was $153.3 million, which was up 3% from the prior quarter. Adjusted EBITDA based on reported earnings was $31.7 million. If you exclude the negative impact of the Colombia tax adjusted EBITDA for Q1 would have been $38.9 million. This compares to $37.7 million in Q4 and $9.2 million in Q1 of last year. Looking at our Drilling Division performance, our revenue in Q1 was $99.8 million which was up 5% from the previous quarter.

Our Colombian operations counted for $24.2 million of that total which is down about 5% from Q4, and that is due primarily to periods of downtime that affected two of our rigs in Colombia during March. One of these rigs began earning mobilization rates in April and the other is expected to be earning full day rates again in late May. Our turnkey drilling revenues more than doubled from the prior quarter to $7.9 million. We completed six turnkey jobs in the quarter. Looking forward we expect to return to a range of two to four jobs per quarter.

Our gross margin for Drilling Services was 32.3% compared to 33.7% in Q4. This slight decline is primarily due to the increased revenues from turnkey operations. While the turnkeys contribute higher gross margins on a total dollar basis, the gross margin percentage tends to be lower due to the higher top line. Average margin per day increased about 1% from the previous quarter to 7769, and our overall utilization increased to 100 percentage points from Q4 to 65%, and as of this week it stands at 69%.

We currently have 32 rigs working under term contract, and an additional nine rigs under contract to begin operating in West Texas through the rest of the year as Stacy discussed. Of the rigs currently under contract, 25 are operating in the US and seven are operating in Colombia. As mentioned earlier we expect our eighth rig in Colombia to return to work under contract later in May, and as of March 31st the average remaining contract term was nine months with six months on average for the US rigs.

Looking now at the Production Services Division, our revenues were $53.6 million in Q1, up by less than 1% from the prior quarter. Overall activity levels were lower in the quarter due to weather and reduced daylight hours, however the increased number of units enabled Production Services’ revenue in the quarter to remain flat. Overall gross margin was 38%, down from 41.5% in the prior quarter. The decrease in the margin was the result of the reduced activity levels I just discussed as well as some increased costs due to recruiting and training crews for new units.

Well servicing utilization was just under 82% in Q1 compared to 90% in Q4. Our activity picked up nicely in April and with an average utilization of approximately 88%, and our average hourly revenue rate increased by $6 from the prior quarter to $509 per hour. Overall, Production Services represented approximately 39% of the company’s gross profit in Q1.

Company-wide G&A costs were $14.5 million compared to $15.3 million in Q4, and the prior quarter G&A was higher due primarily to year-end accruals for performance-based incentive compensation. Our Q2 G&A will likely increase from Q1 by around $500,000 based on the current outlook.

Depreciation and amortization costs were $32.3 million which is up $720,000 from Q4. Our interest expense for Q1 was $7.5 million which is down $300,000 from Q4. This is due to lower average debt outstanding throughout Q1 and a lower interest rate as well. As our leverage ratio improves our interest rate on the revolving line of credit declines. Our effective tax rate for Q1 was 25.8%. This reduced rate is due to the non-deductible Colombian tax of $7.3 million partially offset by other permanent differences. For Q2, Q3, and Q4 of 2011 we currently estimate the effective tax rate will be in the 38% to 40% range.

Looking over the balance sheet during Q1 our net borrowings were $4.2 million on our revolving credit facility, resulting in $42 million outstanding under the revolver as of March 31st. We also have $9.2 million in committed letters of credit which leaves our borrowing availability at $173.8 million. Our cash and cash equivalents were $15.3 million as of March 31st. The total consolidated leverage ratio for the company was 2.2:1; our senior consolidated leverage ratio was 0.4:1; and our interest coverage ratio was 4.5:1.

Capital expenditures during Q1 totaled $34.7 million and that included $13.1 million for routine expenditures. For the full year we now expect to spend $170 million to $185 million of CAPEX which includes funding for two new builds as well as upgrades and relocations for 14 to16 drilling rigs to West Texas. Again, that number could go higher if we are successful in signing additional term contracts for new build rigs or we decide to add additional Well Servicing or Wire Line units. And with that I’ll turn it back over to Stacy.

Stacy Locke

Thank you, Lorne. Before opening it up to questions I’d like to talk a little bit about how we see our market playing out in the short-term and a little bit in the long-term. On the drilling side, as we talked about in last quarter’s conference call, all of our shale capable rigs are already in the shales working, and we have pushed those day rates up right to market rates; and we’d pretty much done that last quarter, and that’s why we gave minimal improvement in average margins per day on the drilling side. So for us our growth in revenues and margin per day is going to occur from putting stacked rigs back to work in West Texas albeit at a lower average margin per day than we have in the shale activity rigs; and then later from our new build program, which that will really impact the company more in 2012.

So for this year while there may be some modest improvements in day rates even in the shale plays, we’re going to have a little bit of an average margin downdraft because of the increased activity out in the West Texas market. That is still a great opportunity for Pioneer. It’s taking stacked equipment, putting it back to work in very high returns and is increasing our EITDA in each quarter going forward. As you can see from the schedule that I laid out in my prepared notes a moment ago, the impact from West Texas is minimal in Q2. So we don’t see much change taking place in Q2 but a greater impact in Q3, Q4 and beyond. And of course on the new build side, we see that market really being a 2012 event and we remain optimistic that we’ll layer in additional new builds to the one we’ve announced.

So the guidance that I’ll give for the Q2 is modest improvement in utilization, maybe up just 2% to 4% on average which would be 67% to 69%, and margins being flat to roughly slightly down, maybe as much as $300 a day. That’s a little hard to gauge but it’s not going to be a ramp up due to the gradual increase in rigs going into West Texas. And that trend should continue for the balance of this year unless we later see that our shale rig day rates are pushing upwards, which I think we’re really not seeing that right now.

On the Production Service side of the business we do see a rebound in Q2. We think revenues are going to come back up 5% to 10%, and we think margin as a percentage of revenue should increase 100 basis points to 300 basis points to a 39% to 41% margin. And we see that business improving steadily through the course of the year from the information that we have today. As you know, on the Well Service front we’ve been the utilization and pricing leader. Others are narrowing that gap which is going to be good for the overall market and will allow all of us further advancements as the year progresses.

So that is all the prepared remarks for today. We’d like to open the call up for questions, thank you.

Question-and-Answer Session

Operator

We will now begin the question-and-answer session. (Operator Instructions.) And our first question comes from Judd Bailey with Jefferies & Company. Please go ahead.

Judd Bailey – Jefferies & Company

Thanks, good morning guys. Question or follow-up, Stacy, on your guidance for Q2: if the two rigs in West Texas don’t start until June, you think you could have that much of an impact, potentially as high as $300 a day in margin? Are you being conservative or are there some costs with moving the rigs out there? Since it’s so late in the quarter can you give a little color on (interference).

Lorne Phillips

Judd, this is Lorne. I’ll take that one. It’s a couple things. One is we’ll have a full quarter of all the rigs that are, the four rigs that we talked about in our last call that are now operating in West Texas, so all four of those for a full quarter plus adding the other two. And then we talked about how we had some downtime in Q1 with our Colombia rigs but also we have the second one that’ll start back up here in late May and have one earning mobilization rates which was a little bit lower. So a little bit in Colombia, some across the West Texas rigs is kind of the main combination that leads us to give you that range.

Stacy Locke

And we are subsidizing a little bit of the move for some of those rigs out to West Texas, so that impacts it a little bit as well.

Judd Bailey – Jefferies & Company

Okay. If we see rates start to move up in the next few months, it sounds like with the backlogs that you have would it be fair to say if we start to see improvement in the margins it’s probably going to hit in Q4 this year and Q1 of ‘12?

Stacy Locke

Yes, I think that where we’re going to see some help is as we start layering in new builds obviously because those are at the higher end of the market. But also if the existing rigs that are working in the shale plays, if those rates move up then that could impact Q3, Q4 and that’s a possibility. But there’s so many new builds as you’ve heard from all these other calls being put on the market I think the new build pricing is layering in right above where… And I talked about this on the last quarter’s call, that the folks that are seeing average margins go up it’s because of new builds, and I don’t think that too many people are moving up on an existing stock fleet.

So there’ll need to be a change in the market to have these rates go up and that’s a possibility, but I think it’s a little uncertain because there’s so many new builds coming onto the market and being marketed that I think it puts a cap on day rate movement. However, those that are successful in adding lots of new builds, they will see their average margin go up.

Now, I think where the greatest leverage will come – which for us might be a little more of a 2012 event – is I think there’s upside more in the conventional rig market today than there is the high-end shale rig market, other than new builds. We think that West Texas, there is just continued demand there and we’ve taken our first four rigs out there on roughly six-month terms. This next batch will have a number on one-year terms so not much can happen until a year, the anniversary dates of those rigs, but if there’s a market that I see that is probably going up it’s the conventional rig market.

Now, that’s West Texas. In the non-West Texas conventional rig market we are seeing improvement in certain markets, but I would exclude say East Texas where that has just been very anemic – in fact today I think we’re running two rigs in a market that was once our largest market. It’s just very slow and it’s gas price dependent. Now things are changing in a number of these markets. There is a little oil play that’s being potentially developed in East Texas that these rigs would be very suitable for, not unlike what you see in West Texas. So there are opportunities and new plays developing all the time for the conventional fleet, but I think that’s where the most likely leverage to day rates will be.

Judd Bailey – Jefferies & Company

Alright, great. Thank you.

Operator

Thank you, and our next question comes from the line of John Daniel with Simmons & Company. Please go ahead.

John Daniel – Simmons & Company

Good morning, guys. First on Production Services, you guys gave helpful guidance for Q2 but if you could look into your crystal ball beyond Q2, I mean it would seem that revenues should continue to go higher just given the capacity additions that you talked about and the potentially new 600 XL power rigs that you order. But beyond Q2 how do you see margins evolving?

Lorne Phillips

Well, John, based on what we see today we had kind of a seasonally-stopped Q1 and maybe impacted a little bit by weather, but I think that Q2 and Q3 and Q4 are usually pretty strong. So we think, we’ve given guidance for Q2; we would anticipate Q3 to be a little better and Q4 to be even a little better yet. So we see utilization levels, activity levels staying fairly strong and we still think there’s a real opportunity for some pricing improvements, particularly now that a lot of the other folks in the market have brought their pricing and utilization up. It’s going to help everybody.

John Daniel – Simmons & Company

Fair enough. I want to come back to follow-up on Judd’s questions. You mentioned in the prepared remarks the average term on the West Texas rigs is roughly six months. As those rigs are rolling off, is it your view that excluding the West Texas rigs for one moment but the rigs that would be rolling off in current markets, do they price at higher rates? I mean should we expect to see cash margin on that segment of rigs go higher? And let me just throw one more to you big picture – can you just comment on some of the discussions you’re having with customers for those rigs?

Stacy Locke

Right, well those activity levels are still strong and I would say that we are moving as those rigs- We are able to recommit to terms in almost all cases – we’ve been somewhat insistent on that. And I would say that generally we are getting a little bit of price improvement but it’s not like stepping up $2000 a day; it’s smaller numbers. It’s either the same or slightly up, probably on the order of $500, maybe $1000 a day. But it just varies.

Some rigs are where I would say are completely topped out. We have a number of them that I would say are right at the top of the market, and so as an overall fleet I don’t think – and that’s why our guidance is the way it is. I don’t think- You know, there could be a little bit of a positive upside surprise but it’s just very hard to determine that with so many contracts kind of moving at different spots and already being high in the shale plays.

John Daniel – Simmons & Company

Okay. Just one last one then I’ll get back in the queue. Lorne, I don’t know if you said the depreciation guidance for Q2. If you didn’t can you give us a sense as to what you’re expecting?

Lorne Phillips

Yeah, you’re right, I didn’t. We were $32.3 million in the first and I think it should be around that range. My guidance in the last call for the year was $124 million to $128 million, and I think it’s going to be in the high end of that range. I would probably use the current run rate for now. New builds, we’ll be spending on those this year but they won’t go into service probably until say Q1 2012, and so you really won’t see the impact of that on G&A this year. So I would use current run rate, maybe up just a little bit but I think that’s probably the right guidance on it.

John Daniel – Simmons & Company

Okay, thanks guys.

Operator

Thank you, and our next question comes from the line of Brian Uhlmer with Global Hunter Securities. Please go ahead.

Brian Uhlmer – Global Hunter Securities

Hey, good morning, gentlemen. How you guys doing? I have two questions relating to the West Texas rigs. First you said that you’re subsidizing some of the move expenses. I was curious to what extent that would be and how that’s going to affect the OPEX as you move them out and get them ready. And then second, as you get those rigs ready, what portion of kind of bring them out of the yard costs are going to be capitalized and how much is that going to hit the OPEX? So should we see sort of an upward trend in Q2 that’s reversed in Q3 I guess is what I’m really looking for?

Lorne Phillips

This is Lorne. I guess in terms of how it impacts us, most of that is capitalized. You do have some expense associated with your crews as you’re moving out there and getting the rigs set up, but the vast majority of the cost is capitalized cause a lot of it has to do with equipment. And then from a mobilization perspective, it does hit but it doesn’t hit all at once. If you’re under term contracts it kind of gets amortized over the term of the contract. So I wouldn’t, you ended your question with kind of an updraft followed by a downdraft with your question I thought and I don’t think we’ll see that. I think the guidance of our margin per day sticking in the flat to down $300 is what you should be focused on.

Brian Uhlmer – Global Hunter Securities

Okay, even moving beyond Q2, okay?

Lorne Phillips

Oh sorry, you were saying beyond Q2?

Brian Uhlmer – Global Hunter Securities

Yes.

Lorne Phillips

Oh, well I guess I need to kind of defer to Stacy’s comments in far as I think as you get the rigs out there, and they’re going to keep going throughout the year, but I think you’ll see probably a gradual decline like Stacy talked about, flat to decline as the years go on and as they come in and get into service and the margins per day, utilization EBITDA going up, margins per day probably trending down.

Brian Uhlmer – Global Hunter Securities

And further out on the long-term prospects for these guys if can you explain the capabilities of the rigs and the formations you’re targeting and give us a little bit of comfort that these are going to get contracts through 2012, 2013 and don’t get displaced by new builds. Can you kind of speak to that a little bit, Stacy?

Stacy Locke

Sure. Well these rigs… I have to be honest. I think demand’s driving most of it but secondarily to demand is the quality of the rigs that we’re taking out there, and I think that has played a role because as you’ve heard me say in the past our mechanical conventional fleet is high end. Most of these rigs have the roundabout a mud tank just like a brand new rig, they’ve got high horsepower mud pumps, max 1000 horsepower at a minimum. These are pretty much all 1000 to 1200 horsepower rigs.

So they’ve got, every one of them has an iron roughneck, they’ve got dual linear motion shakers cleaning the mud. So in many respects they’ve got a lot of the attributes of the most modern rigs built out there and even a lot of the engines are modern tier low-knock engines. So what they don’t have they’re not SER or they’re not joystick and they don’t all have top drives, but as a West Texas rig goes, I think they would be considered very high end and I think they’ll perform at a very high end. So I think that has helped us break into a whole multitude of customers there, so I am confident that we will roll those over. As long as these oil prices stay strong and activity is high then our rigs will stay working, I’m confident of that.

And as I said before, I think it’s more likely than not that as the initial contracts roll you’ll roll to higher day rates. So we’re, I think that we’re hopeful that this will become one of our largest operating divisions here by Q4 or Q1 of next year.

Brian Uhlmer – Global Hunter Securities

Outstanding, great answer. Thank you.

Operator

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

John Keller – Stephens Inc.

Hi, good morning guys. Just wanted to kind of drill down on the new build capacity a little bit – it’s clearly positive you got the first one signed. How many from an operational standpoint do you think that you guys could take on and actually kind of move forward with?

Stacy Locke

I would say we would not want to get into a position where we were putting out more than one a month. We’ve heard lots of horror stories out there about some of these folks who are putting out two or three a month in terms of really diluting their crew quality and we would not want to fall victim to that because we are really interested in safety and service and that’s being able to perform the task. So I would say that most, like in 2006 we were able to put out one new build a month. I don’t think we’ll get to that level. I think maybe we’d put out perhaps two rigs, certainly one rig a quarter but possibly two rigs a quarter; if things really get ramped up maybe one rig a month, but I don’t think we would want to build more than one rig a month because we just can’t get the crews trained and the quality to perform the service properly.

John Keller – Stephens Inc.

And then how about from say a balance sheet standpoint? I mean how many would you feel comfortable kind of committing to and how would you think about financing if you got to a more steady or higher run rate in terms of your new build deliveries?

Stacy Locke

I’d say one benefit of having not contracted these new builds before today is that we’re seeing our EBITDA improve and our operating cash flow just getting better each quarter going forward so that’s going to help us do more out of cash flow. We think we can pretty much do a couple out of cash flow this year maybe with modest borrowing; next year we’ll have even more improved cash flow so we can do some additional out of next year’s operating cash flow. And so I think we can handle cash flow from existing operations and some borrowing. There’s going to be periods where there’s a tight spot here or there and we may need to borrow a little more under our line and then let our cash flows build and pay it back, so really it’s been a mixed blessing to have the delays in getting these first contract signed.

And I think what we’re seeing now if I was to predict in our new build negotiations, I think we’re going to see kind of exactly what I’m describing is we’ll be able to have an opportunity to layer in some of these new builds through the Q1, Q2, and Q3 of next year and not have them stacked up right in Q1 which will help fund them.

John Keller – Stephens Inc.

Got it. And then just one more – as you build out your West Texas operation can you maybe just address how you’re going about securing crews for that? I mean labor’s incredibly tight in that market and you guys are moving there pretty aggressively. So any challenges there or how you’re addressing it?

Stacy Locke

Well, it’s absolutely a challenge. We have been able to get these rigs crewed up with crews before they leave and that’s helped but it’s just going to be- We’ve faced this before and it’s a challenge in pretty much every market we’re in, in the Bachan [ph] and the Marcellus, even South Texas. You know, a lot of the crews have come from slower markets like East Texas, like North Texas, like out in some of the rocky areas that are more gas so we fortunately have had tentacles out in tall those markets and we’ve been able to access crews.

A lot of our crews are managers that started out in West Texas, they’ve all relocated out of our North Texas division. And so it’s been helpful that we’ve been out and around for a while and have access to quite a few different groups of people. But it’s going to be a challenge and we’re having to put extra crew on to train them, extra drillers, extra floor hands just to ensure that we have a good crew quality. But it’ll continue to be a challenge, no doubt about it

John Keller – Stephens Inc.

That’ll do it for me, thanks guys.

Operator

And our next question comes from the line of Jim Rollison with Raymond James. Please go ahead.

Jim Rollison – Raymond James

Good morning, Stacy. New build, or excuse me, reactivations – any guidance on kind of what the cost is and just generally what you’re doing to get these rigs up to where they need to be for heading out to West Texas?

Stacy Locke

Yes, I would say the first batch, I’m trying to go back on my memory here, I think I’m roughly correct but the first batch of rigs that we started marketing, that first four I think we were estimating at about $750,000 per rig roughly, somewhere in that range. This second batch that we’re now working on taking out there, that cost has gone up probably closer to $1.5 million, $1.75 million a rig; and then the next batch that we will probably start marketing here soon, I would guess an estimated cost of no more than $2 million a rig. And I don’t think you know, if the rig’s going to cost much more than that we’ll probably not try to invest that level of capital.

Jim Rollison – Raymond James

Got it, the margins aren’t quite there to get the returns you want I assume. Just kind of back to one of the questions you were talking about before as far as funding the reactivations, the new builds, it sounds like you have opportunities to continue adding some reactivated rigs and some new builds. How far out on the leverage point are you willing to take it before you cut things off, until all this stuff hits the ground running and you start bringing that back down through cash flow?

Stacy Locke

Right, well as you’ve heard us say many times in the past, we definitely want to de-lever over the long haul but you also don’t want to let these opportunities go by so you’re in a bit of a catch 22. I’d say we’d be willing to walk out a little bit further on the leverage limb but not much further, and then at some point we would restrict growth and let our cash flow catch up with us. So yeah, we’re very interested in de-levering over time but it’s kind of like you almost have to grow yourself out of that leverage to some degree too.

Jim Rollison – Raymond James

Okay, and then lastly just on the Production Service business, your revenue guidance of up 5% to 10% – I guess when I think about the new equipment added in the quarter, the 14 wire line units, the three service rigs, did those come in relatively late in the quarter? I’m just trying to gauge how much of your sequential guidance is the seasonal bump that you normally get and hopefully no weather issues this quarter like maybe you had in Q4 versus the equipment. It seems like you could be up more than that depending on the timing of when this equipment came in.

Stacy Locke

Right. Well there’s a lot of it that’s in and not yet dispatched to the field, and we’ve opened a number of start-up operations so that’s why- You know, if we had it all in in the beginning of the quarter and everything was working then you’re correct – you could see a greater increase just from the seasonal rebound. But we’re going to be incurring, as Lorne was saying in his comments, we’re going to continue to incur some lingering start-up costs because we’ve opened up in a number of new markets in both Well Service and Wire Line, and the size of these new districts isn’t up at an efficient operating level yet. So we need to get these new units dispatched into them and get them up working and then it’ll kind of spread out the upfront fixed costs that we’ve incurred to establish the new districts. So that’s why we’re giving what I think is somewhat conservative guidance here until we get these units up and running and get these markets established for us.

Jim Rollison – Raymond James

So as those units go to work throughout the quarter you’ll still have revenue growth beyond Q2 from them as well as once you get the costs spread out you’ll get margin improvement as well.

Stacy Locke

Right. I would say most of the revenue improvement from the new units will benefit Q3 and Q4 than Q2. I think right now we’re trying to get them all sorted and get these new districts established and get customers – it’s a lot about positioning.

Jim Rollison – Raymond James

Okay, thanks very much.

Operator

Thank you, and our next question comes from the line of Janice Rut with Pritchard Capital. Please go ahead.

Janice Rut – Pritchard Capital

Good morning. I just wanted a little more color on the contracts of the new build. I’m assuming you can’t tell us who it is but maybe describe them – where do you think the rig’s going to go, how long a term is the contract?

Stacy Locke

Well, I’m going to answer that very vaguely. You know, this market for new builds as I’m sure you’ve listened to everybody else’s calls is about as intense a competition as I’ve ever heard or seen, and so we’re not going to really- I will say that most of these new builds will go into unconventional plays, probably mostly the shale plays that would be most obvious like the Bachan, like the Marcellus, like the Eagleford. And I would say that the term for us I would anticipate would average very close to three-year terms. I think we’ll have some greater than, some slightly less than, but I would say the average term length is going to be fairly close to a three-year term – that’s what we’re targeting. So but I don’t want to get into any specifics on any one contract.

As we secure additional contracts then I can give you some blended averages but I don’t really want to identify where these are going. I will say they’re with good customers and they are I think good economic returns to the company.

Janice Rut – Pritchard Capital

Okay, thank you.

Operator

And our next question comes from the line of Roger Reed with Morgan Keegan. Please go ahead.

Roger Reed – Morgan Keegan

Good morning. A lot of this stuff’s been beaten up pretty good but I think I’ll go with some of the stuff when you were talking with Jim Rollison about the cost you’re incurring as you’re moving this equipment in the Production Services part of the business, building out it sounded like some new facilities or within existing facilities. I wasn’t sure which but I’m just trying to understand in general as we look to the back half of the year other issues that you’re incurring that could lead to some margin expansion not connected to pricing improvements.

Stacy Locke

Well, that’s a good question. I guess just to give you an example, let’s say we’re starting an operation in the Marcellus in Wire Line and Well Service. You’ve got to secure your people – your managerial, your supervisory-level people – and you usually do that before that first unit’s there. You will not reach, then you secure additional staff as those areas grow but you know, these district offices need to get to a certain critical mass before they really are optimized and so you generally like to have at least four or five units in each district office working to start operating at efficient levels.

And so we’ve established and we have been establishing a number of districts in all the shale plays that we all know about and in some cases multiple districts in shale plays, the ones that are particularly lengthy, and so you know, you might start with one unit and then a second unit and then you get this batch of units in this quarter, this past quarter and then you’ll be able to feed in a third unit. So and at the same time you’re also trying to establish new customers so it just takes a little bit of time to get these new districts up and running and for us, we just feel it’s important.

We’re believers in these plays long-term and we feel that we need to be in there, be established and in some cases maybe a little on the early side but we think that pays off in the long run and that’s just the way we approach the business. So yes, down the road, maybe even as early as the end of this year and certainly next year we will start achieving greater efficiencies in a lot of these districts.

Roger Reed – Morgan Keegan

Okay. So kind of following on with a question, is that something you can see as an enhancement to margins in Q3 and Q4 or let’s say we’re going to be building things- It’s not like the shale play approach is slowing down, so I mean even after the current build-out you’re doing there will be another district to add and another part of the Eagleford or Marcellus or wherever. Based on your plans I mean do you see that or not?

Stacy Locke

We do. I mean we’re pretty well situated in a lot of the major plays. There are a few markets that we haven’t opened yet but we do have at least seed establishments in most of these big plays and so I do think we will see some margin improvement in Q3 and Q4 probably each and then we’ll probably have a little bit of a seasonally slow start to Q1 next year, but right now we see a gradual improvement in the margins. So and then it’ll be further enhanced as we have all our districts established, which probably you’ll see the full benefit of that more in 2012.

Roger Reed – Morgan Keegan

Sure, I understand that. And then coming back again on the margin on the Drilling Services side, in terms of a starting point for the impact of the West Texas rigs, or the margins on the West Texas rigs, is it best to start from where we were in the Q4 when you had nothing out there or is it better to start with Q1’s cash margin in terms of layering in the impact of the four rigs and then ultimately the nine?

Lorne Phillips

I would start with going with the Q1. I mean Q1 and Q4 are close, so I would take this Q1 probably and go from there. I mean it was a $100 margin per day difference.

Roger Reed – Morgan Keegan

Okay, thanks. Yeah, I was just trying to understand if there was anything unusual in either quarter.

Lorne Phillips

No, there’s always a little noise in every quarter it seems like, but you know we’ll end up at the end of the year with 13 rigs out there, correct?

Roger Reed – Morgan Keegan

Yeah, four and then nine, right?

Lorne Phillips

Four plus nine, right. And also on your prior question, just to put a little bit of perspective on it, we were, the Production Service margin in Q1 was 38%. Just as a reminder, in 2008 we were up over 50% in that business and we were growing pretty good then, too. So we still have a lot of upward opportunity in that margin we think. Pricing is not back in any of those businesses yet to ‘08 levels so there is quite a bit of upside there over time.

Roger Reed – Morgan Keegan

Maybe as a quick question on that on the pricing side, what would you identify as kind of the biggest impediment to price? I know ‘08 was a phenomenal 2000 rigs running plus, but what are the impediments to pricing at this point in the Production Services segment? Clearly it’s good enough to incentivize you to add equipment at this point but pricing, is it capacity or how do you go about that?

Lorne Phillips

Well, I think what you had in ‘08 that you don’t have today was great gas prices, and fortunately we’ve had oil and all of these new oil and liquid rich plays develop – that’s really creating the opportunity that we have today. But gas is going to come back at some point, and when gas prices come back which possibly could start happening next year or the year after, then I think you’ll optimize pricing on all fronts. Obviously that would give you the chance to take the production services businesses back up to that 50% and beyond level, and then on the drilling side we’re still a far cry from the highest average quarterly margins we had in our fleet back in ‘08 which was just about 10,000 a day, just shy of 10,000.

And our fleet is vastly superior with 35 of the rigs with top drives, we bought 30-some-odd pairs of 1600 horsepower, 1300 horsepower mud pumps; we’ve added a lot of iron roughnecks, we’ve added a lot of features to these rigs that when gas prices in the whole market improves where you have both commodities working that we should see our average margin fleet-wide up above where we were in ‘08.

Roger Reed – Morgan Keegan

Okay, that’s helpful. Thank you.

Operator

And our next question comes from the line of Mike Kelly with Kennedy Capital. Please go ahead.

Mike Kelly – Kennedy Capital

Hey Stacy and Lorne, how are you? Given that we saw a sequential increase in daily drilling costs by almost 8% and gross margins falling about 140 bps in that segment, I was hoping you could talk just briefly on the cost pressures you’re seeing in this segment and the potential for more pressure on the gross margin?

Lorne Phillips

Mike, this is Lorne, Stacy will probably follow up with some stuff but one thing I would just reiterate is that you know, our turnkey volume went up quite a bit and that does drive up your revenue per day to some extent which went up this quarter and then your operating cost per day as well. And I was trying to explain you do get a better margin per day on it, but because you’re top line is flowing so much through on the turnkey it actually has a dilutive effect on your gross margin percentage. So that’s part of it.

Now, there are pressures out there but most of that we’re able to pass on but things like Stacy was talking about where maybe you’re training more crews, more people on your crews carrying extra employees so that you can deliver good crews is something that probably is impacting us a little bit. Stacy, do you have anything to add?

Stacy Locke

Well, I was just going to put a little color on that. When you think about it, the types of costs that Lorne is talking about on these turnkeys, it’s the costs for the casing, it’s the costs for the mud, the bits, the supervision, the cementing crews, the casing crews – all of that cost goes through the revenue line on those particular jobs. So your revenue per day on a turnkey, they’re sometimes over $40,000 a day in terms of cost? Is that about right?

Lorne Phillips

Yeah, it can reach that point.

Stacy Locke

It can reach that $30,000 to $40,000 a day just because you’re running all that cost that we don’t normally run when we’re on just pure day work. So that really clouds up in quarters where we are doing more than normal numbers of turnkeys your revenue per day and your cost per day will jump up and it always causes great concern for people because they don’t realize the impact of these turnkeys. I would say baseline day work cost, if we stripped it out, probably didn’t change much quarter to quarter.

Lorne Phillips

Yeah, that is correct.

Stacy Locke

Yeah, so it’s really the impact of the turnkeys.

Mike Kelly – Kennedy Capital

Great, that’s what I was looking for. Thank you.

Operator

Thank you and our next question comes from the line of Jeff Kagan [ph] with Milwaukee Private Wealth Management. Please go ahead.

Jeff Kagan [ph] – Milwaukee Private Wealth Management

Good morning. Stacy, under what circumstances do you believe natural gas prices will firm and go higher?

Stacy Locke

That’s a great question. You know it’s a little hard to envision right now I’ll be the first to admit because what’s killing it is these unconventional plays where they’re going for the liquid but they’re producing a heck of a lot of gas. So it’s a little hard to see. However, I will say this, that in my 16 years’ of experience with the company I have been surprised numerous times on commodity pricing, and I just generally believe that gas prices for whatever combination of reasons – like you have another winter like we had this past year – and then eventually the US will come upon a feasible energy policy that will create demand.

I know that’s somewhat long-term but I think that should happen and could happen quicker than we all think. So you know, I’m confident when I say gas prices will come back. I don’t know that it’ll be next year but I wouldn’t be surprised to see gas prices up on average a little bit next year and then up on average a little bit more the following year, and I don’t think it takes too much more and with some spikes in there that give people hedging opportunities to keep some of that drilling going.

Jeff Kagan [ph] – Milwaukee Private Wealth Management

Haven’t we been waiting since the mid-70’s for a national energy policy?

Stacy Locke

Yes we have. I think now’s the time to get it done, don’t you?

Jeff Kagan [ph] – Milwaukee Private Wealth Management

Twenty-five years ago. Okay, second question on if your fleet is equipped or capable of drilling for shale gas today.

Stacy Locke

Well, I think that it depends on what the operators want. And I think that you know, if you go back and you look back in time, for many years there we were drilling shales without top drives, like all the rigs that we built to go to the Barnett shale, not one of them had a top drive and they drilled all that time without a top drive. In the early years in the Bachan, all those rigs didn’t have top drives. So if operators, like we’re seeing in West Texas and certain other markets, they’re using rigs without top drives. We will put more rigs, we could put more rigs in the market without top drives. The issue for us is we don’t want to incur the cost on putting top drives if that’s the direction operators are going. We don’t want to spend that much on an 800 horsepower mechanical rig just because over time that rig could be replaced by a new build, because people are going to still be building new. So we have a lot of rigs that are capable- Let me just say this: every rig that is clearly capable to work on the shale plays is working. There will be some of these rigs that we’ll move to West Texas that’ll also be working in the shale plays and we don’t have to go to the expense of putting a top drive on it. They’ll drill it as it, horizontally like we’ve done in the past.

So I wouldn’t say that in today’s world there’s too many more of our existing fleet that will drill in the shale plays horizontally at least without us having to spend capital to put a top drive on it, and we won’t spend that capital cause it’s usually not just a top drive; if they want a top drive and they’re going horizontal they’ll oftentimes want 1300 or 1600 horsepower mud pumps, and then on a mechanical fleet we’ll have to buy power to source it. So it’s a fairly expensive proposition. Having said that we are looking at that on a case right now where a customer has come to us and they want to replace an AC joystick rig with our mechanical rig and they’re willing to give us an 18-month term at a very high day rate, quite a bit over $20,000 per day. So in those cases we might go ahead and spend that capital to do it but it’s going to take a term contract for us to do it.

Jeff Kagan [ph] – Milwaukee Private Wealth Management

Thank you.

Operator

Thank you, and I don’t show any further questions in queue, Mr. Locke.

Stacy Locke

Alright, well we sure appreciate your participation on the call today, a bunch of good questions, and we will look forward to visiting again next quarter. Thank you.

Operator

Ladies and gentlemen, this concludes the Pioneer Drilling Q1 2011 earnings conference call, and as a reminder a replay for this conference will be available. You can get that information on how to access the replay through the company’s website and this morning’s earnings release. Thank you for using AT&T conferencing and you may now disconnect.

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