Pioneer Drilling Company Q4 2009 Earnings Call Transcript

| About: Pioneer Energy (PES)

Pioneer Drilling Company (PDC) Q4 2009 Earnings Call Transcript February 16, 2010 11:00 AM ET

Executives

Anne Pearson – IR, DRG&E

Stacy Locke – President and CEO

Lorne Phillips – EVP and CFO

Red West – President, Drilling Services

Joe Eustace – President, Production Services

Analysts

Steve Ferazani – Sidoti & Company

Jim Rollyson – Raymond James

Mike Urban – Deutsche Bank

John Daniel – Simmons & Company

Matt Beeby – Morgan Keegan

Andrew Coleman – UBS

Operator

Good morning, ladies and gentlemen. Thank you for standing by. 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, Tuesday, February 16th of 2010. And I would like to turn the conference over to Anne Pearson of DRG&E. Please go ahead, Mark Schober:'am.

Anne Pearson

Thank you, Britney, and good morning, everybody. Welcome to the conference call to review fourth quarter results. But before management makes their formal remarks, I have a few of the usual items to cover. In a few hours, a replay of today's call will be available. It can be accessed via webcast by going to the Investor Relations section of Pioneer's Web site, and also by telephone replay through February 23rd. You'll find the replay information in today's news release.

Information recorded on this call speaks only as of today, February 16th, 2010. So any time-sensitive information may no longer be accurate as of the time of any replay. Management may make forward-looking statements today that are beliefs on its beliefs and assumptions, and information currently available. Although management believes the expectations reflected in these statements are reasonable, they can give no assurance that they'll prove to be correct.

These statements are subject to certain risks, uncertainties, and assumptions, which are described in this morning's earnings release and also in the company's most recent filings with the SEC. Should one or more of these risks materialize or should underlying assumptions prove incorrect, actual results may differ materially. Please note that this conference call may also contain references to non-GAAP financial measures. You can find reconciliations to GAAP financial in Form 8-K as well as in this morning's news release.

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

Stacy Locke

Thank you, Anne. We appreciate everyone joining us on the call this morning. Here with me for the call is Red West, our President of the Land Drilling Services Division; Joe Eustace, President of our Production Services Division; and Lorne Phillips, our Chief Financial Officer.

As you can see from the press release this morning, our fourth quarter was a little better than we had anticipated. Top line revenues were up 8%. That's two quarters in a row now we were up 7% Q2 to Q3, and that's after a difficult beginning of the year where we declined 31% revenues Q1 to Q2. Second quarter was at the bottom with respect to revenues. However, Q4 is the lowest so far in terms of margins and earnings, primarily as a result of term contracts rolling off through the course of 2009.

On the drilling side, revenues were up markedly at 12%, thanks largely to Colombia. Utilization was 41%, slightly ahead of our 40% estimate, and average margins per day were roughly flat with the third quarter at 5,629 instead of being down in the 4,000 per day range as expected. Here again, that was helped by Colombia, and also helped by activating more rigs into the higher margin shale plays. But we also ended up receiving some assistance on some mobilization of rigs for long distance areas. And some of the mobs where we largely incurred some of that cost were postponed into Q1.

A big change for us today is term contract exposure is up to 21% of our total fleet. That's up from 4 rigs at the start of the year to 15 rigs today. Most of those are fairly short 6 months term contracts, but we also have six that are taking us out into 2012. Based on other contracts we have in hand for rigs that are currently working, we'll add another five additional term contracts by April, which will cover roughly 28% of our total fleet.

On the production services side, revenues were up 1% instead of being down 10% to 12%. That's in part due to a better than normal holiday season. We're very pleased to see that. Well services helped. It was up in both terms of utilization. And hourly rate utilization for the quarter was 53%, up from 52%. And average hourly rate was $4.70 per hour versus $4.53 in the third quarter. Fishing and rental was up as well after hitting rock bottom in the third quarter. Wireline was off in both revenue and margin as pricing continues to be fairly fierce in that sector. Overall margin for the production service crew as a percentage of revenue was down slightly more than we expected at 33% versus 37% in the third quarter, mostly again due to Wireline.

I'd like to turn it over to Lorne for a quick discussion on the financials. And then I'll come back and talk a little bit about the market and guidance. Lorne?

Lorne Phillips

Thanks, Stacy. Good morning, everyone. As we reported this morning, Pioneer had a net loss of $8.4 million in the fourth quarter or $0.16 per diluted share. That compares to a net loss of $9.2 million or $0.18 per share in the third quarter. The net loss in the latest quarter reflected a $3.5 million tax benefit for the release of the valuation allowance for deferred tax assets in Colombia. Those deferred tax assets are associated with net operating losses in Colombia that we expect to apply against future taxable income there. If you stripped out the tax benefit, our net loss would have been $11.9 million or $0.23 a share. You may also recall that we had a bad debt recovery of about $1.4 million in the third quarter, whereas in this quarter, it was a very small bad debt expense.

Consolidated revenue for the quarter was $81.2 million, up $6.8 million from the third quarter. EBITDA was $14.1 million, compared to $15.2 million in the prior quarter. For the year, our revenue and EBITDA was $326 million and $75 million, respectively.

Looking first now at drilling services, our revenues were $54.6 million, which was an increase of $6.5 million from the third quarter. Colombian revenues were $17.3 million of the total, and turnkey revenues were $9.1 million. The turnkey business included six completed jobs and two jobs in progress at the end of the quarter. Another $1.2 million was related to rigs earnings standby revenue, but not working. Our last contract in this category expired on December 31st.

Our drilling services costs were up 12% from the last quarter, but operating costs per day were down 6%. The decrease in drilling services per day costs were driven by continued cost containment efforts and pure drilling rig moves in Colombia as compared to the prior quarter. Drilling services gross margin was up slightly from the prior quarter, just under 28%. And as Stacy mentioned, the margin per day of 5,629 was flat with the third quarter.

Moving on now to production services, our revenue was $26.6 million, up marginally from the prior quarter. And as Stacy mentioned, the gross margin was down to 33%, down from just under 37% in the prior quarter.

I'm going to move on now to our SG&A and forecast information. Company-wide SG&A costs were up $0.70 million to $9.6 million. That was driven primarily by the decision to pay limited annual bonuses as well as increased costs related to location to expansions for the Wireline and well servicing businesses. With the increase in activity, we anticipate SG&A going up as we hire additional personnel and restore several items of employee compensation that were frozen or eliminated last year due to the industry downturn. These items include management bonuses, 401-K mass contributions, and merit increases. For the first quarter, we anticipate SG&A in the $10.5 million to $10.8 million range, and between $44 million and $46 million for the full year.

Our depreciation and amortization in the fourth quarter was $27.7 million, an increase of $0.80 million quarter-over-quarter. We expect it to be a little less than a $1 million higher in the first quarter of 2010, and for the full year between $113 million to $115 million. Excluding the one-time impact of the release of the valuation allowance, our effective tax rate in 2009 was 34%. We expect the 2010 tax rate to be in the 33% and 34% range as well.

Moving on now to liquidity and the balance sheet, the fourth quarter balance sheet includes an income tax receivable of approximately $40 million, $20 million of which relates to the recent legislation that allows us to carry back current year losses against taxes paid over the past five years. We expect to receive this $40 million payment in the second quarter of 2010.

During the quarter, we sold $3.8 million of new common shares, raising $24 million in net proceeds. This equity gives us additional financial flexibility and positions us to make our equipment more competitive in the highest value markets.

Cash and cash equivalents at the end of the fourth quarter were $40.4 million, which is down about $9.5 million from September 30th. The decrease is due to capital expenditures of $48 million in the fourth quarter, partially offset by cash from operations of $13 million. Before the year, capital expenditures were $114.7 million, and cash flow from operations was $123.3 million.

At December 31st, 2009, we were in compliance with our financial covenants under our credit facility. Our total consolidated leverage ratio and our senior consolidated leverage ratio was 3.3 to 1, our interest coverage ratio was 9 to 1, and our asset coverage ratio was 1.6 to 1. Our balance under the $325 million credit facility, remained unchanged at $257.5 million as of December 31st. We also have an additional $11.5 million of the facility utilized for letters of credit. Based on the annual excess cash flow repayment requirement in our credit facility, we will pay down $1.9 million of revolver debt in the first quarter.

For the fiscal year ending December 31st, 2010, we have an approved capital expenditure budget of approximately $80 million. About three-fourths will go to drilling services, and one-fourth to production services. Routine CapEx is estimated at $21 million for 2010. We will also be carrying over $17 million of previously approved capital expenditures into this year, a large portion of which is actually related to expenditures that we had budgeted or originally planned for 2010. As a result, with the current outlook, we expect cash CapEx to be at the $70 million to $85 million range for the year.

For 2010, we expect to fund CapEx primarily from cash flow from operations, which does include the tax refund of approximately $40 million I mentioned earlier in my comments. However, the first quarter CapEx is expected to exceed cash flow from operations, and will reverse after the first quarter.

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

Stacy Locke

Thank you, Lorne. Just a few comments on the broader market, as – I think we've probably all been surprised at how rapidly the US land rig count has recovered at the pace we've been following over the last several months. As we continue that pace, by the end of the year, we'll be approaching 2,000 or even more rigs running, which I don't think is really achievable. If you take the monthly average rig count increase from the bottom in June that would put us on a trajectory of about 1,850 rigs by the end of the year. I think that's probably on the high side.

So I think we're – as you would expect, we've had a pretty good recovery in US land rig count. It's actually picked up in rate of change as we approach year-end and people were positioning for their new budget. And I think that it will continue through the course of 2010 and possibly into 2011. However, I don't think that the rate of change that we've seen is sustainable. And I think that – it's hard to estimate at this point, but I think that we should end the year closer to maybe 1,600 rigs as opposed to 1,800 to 2,000 rigs.

So we're still optimistic about the market, but I think that the rate of change has probably been – due to the demand and the shale plays, at some point, they'll reach some saturation has gone into a few quite oil plays, I think the same there. And unless the natural gas price outlook changes fairly significantly, I think that this rate of change will have to plateau. It'll still be on the increase, but it's going to require a better gas price outlook to sustain higher levels of increase.

Having said that, I'd like to talk a little bit about just Pioneer and our guidance. As we talked about in prior calls and you've seen, we have upgraded quite a few of our rigs. Those are the majority of the rigs that are working today. We have had a number of rigs that have not been upgraded come back to work be it at slower margins.

But as we sit today, we've added 22 top drives. That's 31% of our fleet. We have nine more top drives on order that'll be coming in between now and early summer. That's probably fewer top drives, and we have still have rigs to upgrade. We probably have at least 12 to 15 rigs that we would like to upgrade over the next 12 months or so, if not sooner. So the upgrading certainly has helped. It's allowed us to reposition rigs into the higher margin plays.

Having said that, the first quarter of this year, it's been a fairly slow start. We've just recently brought our utilization up. It started somewhat slow, even fell off a little bit at the beginning of January. So for an average on the drilling side, we're anticipating 45% to 47% utilization in Q1, and then increasing each quarter thereafter. I think we'll exceed 50% utilization in the second quarter, and we'll exceed 60% utilization across the total fleet by the end of the year.

In terms of margin, we had forecasted for Q4 a margin of 3,800 to 4,000 a day. I think we were off by a quarter, some of that mob-related. But we will – the impact is a little bit by mobs in the first quarter, also in the first quarter and second quarter. We've had to rent some top drives, which that rental charge is a better part of the margin on those rigs. So that's going to hurt us a little bit. So we think that Q1 will be the bottom in terms of average margins per day. And we're forecasting that to be 4,500 to 4,800 per day, and that being the bottom for 2010.

On the production services side, we've forecasted a 10%, 12% decline in revenues in Q4. We actually were up 1%. We see that continuing. Our fishing and rental is showing a little final life coming back slowly. The well service and fleet is doing much better. We're in the 60% range in utilization today. Pricing is still a challenge there, and still a challenge in the Wireline fleet where the majority of our activity is, those two divisions. So we are going to project revenues up 5% to 7%. But for the time being, we're going to project margins flat with Q4.

That really concludes the prepared remarks. And we would like to entertain any questions at this time.

Question-and-Answer Session

Operator

Thank you, sir. We will now begin the question-and-answer session. (Operator Instructions) Please ask one question and one follow-up, and re-queue for additional questions. And our first question comes from the line of Steve Ferazani with Sidoti & Company. Please go ahead.

Steve Ferazani – Sidoti & Company

Thanks, Stacy. I guess the big question would be – touched on a little bit would be, if we're over producing gas as early as late second quarter. You were talking a few months ago about getting your rigs into places where you're either drilling or for oil or the better economic plays. Do you feel like you're positioned well enough if we saw you as rig count pull back a bit in the second half?

Stacy Locke

I think that's really been our primary strategy, Steve, is to position in the oil market, which as you know, Colombia, we went from five. We'll be up to eight rigs working there. That's very stable. In fact, all those are under – for the most part, under long term contracts. We've increased exposure in the Bakken. We're up to five rigs running there. We'll have a sixth rig beginning in probably about mid-March. And a seventh rig is being upgraded and winterized in Houston currently. And that will start the contract in April.

And then in the Eagle Ford shale, we’d probably – I think most of our activity has been in the oil phase at the Eagle Ford. I think we have three rigs running at the Eagle Ford now. We have a number of rigs in that market that we still need to upgrade and put top drives on. But I wouldn’t be surprised if that rig count does an increase of five to six rigs by the summer or so when we have this top drives in place. So that helps, having the oil driven demand.

And then the other strategy is just the shale plays in general. The Marcellus we’re still – we picked up a fifth rig, which is now being mobilized to the Marcellus. And we’re marketing a number of more rigs. We still anticipate being up to 8 to 10 rigs by the end of the year there. And we’re about to move another rig into Houston and start preparing it for the Marcellus. And we’ll be upgrading the rigs in the Eagle Ford in general. And we’re seeing – we’re actually having some demands to upgrade some of our mechanical rigs. I think today we have three mechanical rigs with top drives, one in the Bakken, one in the Barnett, one in the Eagle Ford area. We've got ongoing discussions about putting top drives on other mechanical rigs as well.

So we’ll see how that plays out. But I think that – we’ve also increased our term contract exposure for that same reason, just to have a little bit more defensive position. We’re still worried about gas prices. Winter is helping, but gas declines haven't really taken place. The broader economic demand hasn’t really come back. So we’re cautious on gas prices, although probably a little more optimistic than perhaps we were just due to the winter weather. But we’re trying to position ourselves to be somewhat defensive to gas prices, and I think we’ve done that.

Steve Ferazani – Sidoti and Company

Okay. Just follow-up, which is beyond decision-making with the longer term contracts, is it depending on if you have to move the rigs to the client is or where they’re going when you going to lock into a contract or why you would stay well-to-well right now?

Stacy Locke

We’ll we’re willing to lock in to longer term contracts where the margins are already at attractive levels. Most of them tend to be in, well, Colombia. But we have – we’ve got a term in the Eagle Ford. We have a couple of three-term in the Marcellus. We probably have four going to six terms in the Bakken. So it’s where we can go ahead and term it out where we feel the margins are still pretty attractive. And I'd say there’s not a lot of demand to lock in for real long periods of time, but we’re exploring that. And where we see there is opportunity, we’ll probably link in some of those terms and increase some term.

Steve Ferazani – Sidoti and Company

Great. Thanks a lot, Stacy.

Stacy Locke

Thank you.

Operator

Thank you. Our next question comes from the line of Jim Rollyson with Raymond James. Please go ahead.

Jim Rollyson – Raymond James

Good morning, Stacy.

Stacy Locke

Good morning, Jim.

Jim Rollyson – Raymond James

You mentioned about 12 to 15 rigs on your short list, I guess, for upgrades some time over the next couple of years. Can you maybe talk about are you having customer interest in those? Would those be on term contracts to protect that investment and maybe just a little color on the margin differential between the not operating rigs you said are working today versus the higher end rigs that you’ve got working on in the shale plays?

Stacy Locke

Right. Well, yes, clearly, like in the case of Colombia, those are costly upgrades. We’re putting in top drives, walking systems, arm roughnecks, and in some cases, automatic catwalks, winterization. So we’re putting lots available weapons on these rigs. And we would like to have terms on – to cover that investment on as many of those as reasonable, though we are pursuing the term on the rigs that we’re upgrading. And I would say that those that are mentioned the, say, 9 to 12 to 15 that we want to upgrade, hopefully that'll be shorter term than two years. We’re trying to do those as quick as we can get these top drives in and get contracts formed. So we’re hoping to do a lot of that this year like we’ve been – it's kind of the same pace we’ve been gong since last summer.

The margin differential, pretty significant for an electric rig that’s been upgraded as a top drive. You’re probably, I would say – well, it’s really hard to, apples to apples. Let me back up and say our lowest horsepower mechanical rigs or lower horsepower even electric rigs are at the low end of the day rate because they’re not being entertained for the shale plays. These are 750 to 900 horsepower. Those margins are probably in the 1,500 or 2,000 a day. So they’re very, very depressed still. We think we’re seeing change there but it’s still pretty depressed.

In terms of the – more than a 1,000 – or heavier 1,000 to 1,500 horsepower electric rigs that we’ve upgraded, I think that you would say on average the margins there have been north of 5,000 a day. So you’re seeing quite a bit of difference. There’s more demand for the – in the shale plays for the 1,000 to 1,500 horsepower rigs. So that’s kind of a value proposition there. And then in between that, you have the upgraded mechanical fleet that is in the 1,000 to 1,500 horsepower.

And that’s a pretty valuable proposition for the operators. Because instead of picking up a rig in the 1,600, 1,700 a day range, they might be able to pick up mechanical rig that can do the same work with a top drive for 1,300, 1,400 a day. So for those that are like mechanical rigs, which there are a number of operators that do, that becomes a very attractive value proposition for the operators, and it’s good for us because our cost basis on those rigs is a lot less.

Jim Rollyson – Raymond James

Very helpful, Stacy. And then just as a follow-up, a modeling question, I guess, you’ve got some of the mob issues you’ve mentioned that are going to impact Q1 and the top drive rentals, which I presume some of that will go away as you take delivery of the new ones. You probably want to get into 2Q precision yet, but it's not about what the total cost impact of that is in 1Q that hopefully goes away as you go to second quarter and beyond so we can figure out the timing of that.

Stacy Locke

I think on the mob cost in Q1 is probably only on the order of $500,000 or so. So that’s under $200 a day impact. And then the top drive, those rigs are just now going to work. They’ll probably work. And I think right now, we have two rental top drives and probably going to go on a third. But that'll impact us probably more in the second quarter. And for those rigs, as I say it’s not many rigs, but that rental on those top drives is a little north of 3,000 a day. So if you’re making 5,000 or 6,000 a day, that’s a good chunk of your margin. So that’s why that hurts, Jim.

We’ve ordered the top drive as quickly as we could get on that. It had a lot to do with why we sold the equity in the fourth quarter last year so we could increase our capital expenditures and order top drives. And that’s exactly what we did. And we ordered some higher drilling horsepower from (inaudible), other things that we knew we would need. So I think most of that will be washed out by the second quarter. And then we’ll see – we do anticipate an increase in average margins, clearly, in the second quarter, and again in the third and fourth quarters. But I just wanted to bring it up because those are some moving pieces that we need to take account of.

Jim Rollyson – Raymond James

Very helpful, thanks, Stacy.

Stacy Locke

Thanks, Jim.

Operator

Thank you. Our next question comes from the line of Mike Urban with Deutsche Bank. Please go ahead.

Mike Urban – Deutsche Bank

Thanks, good morning.

Stacy Locke

Good morning.

Mike Urban – Deutsche Bank

So looking at the US breakdown as a whole that total rig count's still well below previous highs. But the horizontal activity added new record, which is obviously a function of the shale gas plays and some of the oil plays as well. Do you think the industry is at a point or will be at a point soon where you need to see new build rigs or are there still some ability out there, do things like you’re doing upgrading and putting top drives on rigs?

Stacy Locke

I think that the economics are not there to justify a new build at this time. But I think that that – I think there’s a possibility that will change towards the end of the year or certainly early 2011. So we’re positioning for that. But for the time being, I think that the economics do justify the CapEx upgrades to the rigs that already owned, clearly.

Mike Urban – Deutsche Bank

And when you say of this positioning for that – or in anticipation of economics potential getting to that level. Is that something that you’re looking at or in contacting vendors and just looking at designs, and things like that?

Stacy Locke

Correct. We’re just trying to be prepared that when we feel like the internal rate of returns justify the expenditure, we would be in a position where we can begin building new rigs. And so that’s exactly right there, just looking at our designs and fine tuning that, identifying parts, equipment pieces, and just being prepared is all.

Mike Urban – Deutsche Bank

Okay. And on the top drives that you’re ordering, what are you seeing in terms of backlog and waiting times there? Are those starting to stretch out potentially?

Stacy Locke

I think they flip after about, Red, about six months?

Red West

Six to seven months.

Stacy Locke

Six to seven months from this point. So we ordered quite a few in December, and we were able to get some – we’ve gotten some already. Well actually those we probably ordered before December. But the ones that we ordered December, I think we – at that time, we’re able to get some March, and May, June-type deliveries. If we ordered today, it'll probably add on to the end where we’d be getting some July, August, September-type deliveries. And we’re probably going to be ordering some more.

Mike Urban – Deutsche Bank

Okay. That’s all from me. Thank you.

Stacy Locke

You bet.

Operator

Thank you. (Operator Instructions) And our next question comes from the line of John Daniel with Simmons & Company. Please go ahead.

John Daniel – Simmons & Company

Good morning, guys.

Stacy Locke

Good morning, John.

Lorne Phillips

Good morning.

John Daniel – Simmons & Company

I got a few for you. By the way, I like the new web page.

Stacy Locke

Oh, appreciate it.

John Daniel – Simmons & Company

It’s very good. Okay. First thing on the Well Service business, is the sequential increase in rate, is that a function of charging for add-ons, like supervisor charges and tongs [ph]? And if not, do you expect to start charging for those this quarter?

Stacy Locke

I’m going to answer it, and then Joe can tell me if I’m right. I think that Q3 to Q4 increase had more to do with the mix of the business going more to 24 hours. And is that partly true?

Joe Eustace

Very perceptive.

Stacy Locke

Okay. Anyway, so that’s what it is.

John Daniel – Simmons & Company

Okay. Are you starting to charge for those add-ons, bring those back yet?

Joe Eustace

It’s pretty slow in coming. It’s still pretty tight.

John Daniel – Simmons & Company

Okay. On the Wireline side, how would you characterize the utilization today versus Q4?

Stacy Locke

Well, I think the utilization is good. It’s more of a pricing. It’s just been a very competitive market. It just remained competitive most of the year, probably fourth quarter was the most competitive. And it’s definitely – the activity has been (inaudible) and building, but its building probably this year. But it’s still price competitive.

John Daniel – Simmons & Company

Okay.

Joe Eustace

But we do see that improving through the course of the year. But by now, it’s pretty bare knuckles.

John Daniel – Simmons & Company

And I’ve heard about some Wireline capacity up in the Bakken going 24 hours now versus historically daylight. I don't know if that was something you were seeing?

Stacy Locke

Yes, we are, and we’re really enjoying it.

John Daniel – Simmons & Company

Okay. Good. On the CapEx, you mentioned about 20% or so will go towards the Well Service Wireline business. Am I safe to assume that you guys are adding 45 new workable rigs in 2010?

Lorne Phillips

John, this is Lorne. The combination of looking at Wireline and Well Service units, so it’s a mix.

Stacy Locke

But it’s mostly Wireline. It is where – we’re really not pulling the trigger. We still have six stacked without crew rigs out there. We were about to activate another one. And we’re optimistic that those will come off the stack line probably by the summer. But I don't think we’re planning to pull the trigger on a new build for sure yet.

John Daniel – Simmons & Company

Okay. Just a couple of quick ones on the drilling side, can you tell us what the average was in Q4 in terms of contracted rates? And can you break out the contract coverage by quarter for 2010?

Stacy Locke

Well in Q4, we had six that went to four in the quarter, and then we started the New Year with four. And in terms of coverage, I don't have a schedule of that, but I can back into it. As I mentioned, six go out into 2012. And that’s mostly the rigs in Colombia, and then one of the last new builds that we put out. And then we have a couple of one-year term, and then everything else is six months. So you’re sill going to fall off. And then the five-term that we know of that are coming out between now and April, those – three of those will be six-month terms. And one of those will be until the end of 2012. And then one will be a one-year term. So I’d say the contract coverage is concentrated in this year.

John Daniel – Simmons & Company

Okay. Last one for me, if I may. With the $40 million tax receivable you’re going to get in Q2, just by my model for whatever it’s worth, it seems like you probably don't need to tap the equity market this year to fund additional CapEx. Does that jive with what you guys are seeing?

Stacy Locke

Well John, that'll really depend on the market. If the rig count continues like it’s going, which I don't think it will, then we’re going to run out of money probably before we – our rigs are upgraded to meet the demand. But with what we’re seeing in the market, we’re pretty comfortable where we are. We’ll just have to see how that changes in the course of the year.

John Daniel – Simmons & Company

Okay, sure. Thank you, and good quarter.

Lorne Phillips

Hey, John. Just to clarify on that though is – I said in my comments that we expect to cover the CapEx with cash flow from operations based on what we’re looking at in our current expectations that is the case. What Stacy's saying is if it actually grew faster and you got – in the latter half of the year, then that could put you in a situation where we’re spending more than we have available and not covered from cash flow.

John Daniel – Simmons & Company

I understand completely. I’m just trying to tie my model to your thoughts. Thanks, guys.

Stacy Locke

Thank you.

Operator

Thank you. And our next question comes from the line of Matt Beeby with Morgan Keegan. Please go ahead.

Matt Beeby – Morgan Keegan

Thank you. Good morning.

Stacy Locke

Good morning.

Matt Beeby – Morgan Keegan

Operations in Colombia seem to be quite a bit better. Outside of the eights rigs that are working there or plan to go there, are there other rigs in your fleet that you would consider for that market or possibly other markets in South America?

Stacy Locke

Well Matt, we’re – our target going into Colombia was to obtain a division of five to seven rigs or so in Colombia. We are ready – we already are there. We got seven rigs there, and we have an eighth rig going. One area that we do continue to want to pursue in Colombia are moving some of the Well Service operations into Colombia. So that’s high on the agenda. But we’re probably not anticipating moving any more rigs into Colombia at this time. We’ll always explore and examine every situation. But we are pursuing some other countries that have an interest to it, and so we’ll continue to do that.

Matt Beeby – Morgan Keegan

Okay.

Stacy Locke

But (inaudible) at this point.

Matt Beeby – Morgan Keegan

Okay. Great. Then on the – you talked briefly about these turnkey operations you have. Can you tell me how many turnkey jobs that are going on right now and your expectations in the first quarter, and how you look at that through 2010?

Stacy Locke

Currently, we have two turnkeys in progress. And I think the – we’ll be a little down relative to Q4 in terms of total competed turnkeys, I think. But we’re still seeing some turnkey activity. It’s hard to predict because it changes quarter-to-quarter. But I would say we’ll probably do, Red, two to four or one to three per quarter, something like that going forward.

Matt Beeby – Morgan Keegan

Okay. Very good. Thank you.

Stacy Locke

Right. Thank you.

Operator

Thank you. And our next question is from the line of Andrew Coleman with UBS. Please go ahead.

Andrew Coleman – UBS

Hi. Good morning, folks.

Stacy Locke

Good morning.

Andrew Coleman – UBS

I think about the term contract supposedly you guys have, it sounds like a number of them are on six months with a few that will linger longer. Like I said, as you think about the rest of the industry, is that pretty common? I guess are the terms that are in place for those six months of that contract, are they still standardized or is there somewhat (inaudible) in those relative to a longer term one?

Stacy Locke

Well, let me just put it in context a little bit. The long term contract, like a three year term contract, that’s usually only associated with a new bill. Now in our case, in Colombia, that’s what our customer wanted there in Colombia. So we’ll have six of the eight on contracts that will last through the end of 2012. But usually that’s only with when you're putting out a new build. And that's largely driven by the contractor wanting to secure the first most important year's return on investment.

So now that you're out in a market with not really adding as many new builds, you're typical contractor, probably on average, I'd say, six months to a year. That's industry norm for using older equipment that you're upgrading. So we're right in the fairway on that. I think our appetite is probably – just as a hedge against gas price uncertainty, our appetite is probably increased to term a little more on the one year, and in certain cases, we might have operators that'll want to term longer than that. But that's not the norm.

And in terms of the contract we have that are six months, I think we will have – some of those are already three months into the six months. They all vary. So we'll have opportunities at renewals to do another six months or possibly even go a year. So we'll just handle that as those negotiations unfold.

Andrew Coleman – UBS

Okay. Great. Thank you. And the second question I had was just more about – also on the potential for consolidation here in the marketplace. Do you think that given the uptick in activity over the last couple of months that that has remained as strong an idea in folks' minds? Or are folks starting to feel like maybe we might see some stabilization because of the cooler weather, better gas stores, et cetera that might not lead to as much concern on consolidation?

Stacy Locke

I'm not sure in today's market where the consolidation really gets you anymore. It's become a new build economy. And with some of the big contractors providing so many new builds, that's really the playing field we're in. So the customers now have become accustomed to having all the bells and whistles, having the top drives. They're drilling more in the shale plays. So I think – I really think consolidation is less likely today than it was in the past because I think the market has shifted more towards a new build type environment.

Andrew Coleman – UBS

Okay. Great. Thank you very much.

Stacy Locke

Thank you.

Operator

Thank you. (Operator Instructions) And there are no further questions in the queue. At this time, I would like to turn the call back to Mr. Locke for any closing remarks.

Stacy Locke

Okay. Well, thank you very much for participating on today's call. And we look forward to visiting with everyone after the first quarter. Thank you.

Operator

Thank you. Ladies and gentlemen, this concludes the Pioneer Drilling fourth quarter earnings conference call. Details for the replay of this call can be found in today's news release. We thank you for your participation. You may now disconnect.

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