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Executives

Ben Burnham - IR, DRG&E

Chris Strong - President and CEO

Tina Castillo - CFO

Analysts

Max Barrett - Tudor, Pickering, Holt

John Keller - Stephens Inc

Andrea Sharkey - Gabelli & Company

Victor Marchon - RBC Capital Market

Jud Bailey - Jefferies & Company

Conor Ryan - Deutsche Bank

Union Drilling, Inc. (UDRL) Q3 2010 Earnings Call November 3, 2010 10:00 AM ET

Operator

Welcome to Union Drilling’s third quarter earnings conference call. During today’s presentation all participants will be a listen-only mode. Following the presentation the conference will be opened for questions. (Operator instructions) As a reminder, today’s conference is being recorded Wednesday 3rd, November 2010.

I would now like to hand the conference over to Mr. Ben Burnham, with DRG&E. Please go ahead.

Ben Burnham

Thank you Josh and good morning everyone. We appreciate you joining us for Union Drilling’s conference call today to review third quarter 2010 results. Before I turn the call over to management, I have some details to run through.

You may have received an email of the earnings release yesterday afternoon. If you didn’t get your release or would like to be added to the email distribution list, please call DRG&E at 713-529-6600.

A recorded replay of today’s call will be available until November 10. Information for accessing the telephonic replay is in yesterday’s press release. The replay will also be available via webcast by going to the company’s website at www.uniondrilling.com

Please note that information reported on this call, speaks only as of today, November 3, 2010 and therefore you are advised that time sensitive information may no longer be accurate at the time of any replayed listening. Also, statements made on this conference call that are not historical facts, including statements accompanied by words such as may, believe, anticipate, expect, estimate or similar words, are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, regarding Union Drilling’s plans and performance.

These statements are based on management’s estimates, assumptions and projections as of the date of this call and they are not guarantees of future performance. Actual results may differ materially from the results expressed or implied in these statements, as a result of risks, uncertainties and other factors, including but not limited to the factors set forth in the company’s prior filings with the Securities and Exchange Commission.

Union Drilling cautions you not to place undue reliance on forward-looking statements contained in this call. Union Drilling does not undertake any obligation to publicly advise or revise any forward-looking statements to reflect future events, information or circumstances that arise after the date of this call. For further information, please refer to the company’s filings with the SEC.

During today’s call management will discuss EBITDA and drilling margin, which are non-GAAP financial measures. Please refer to yesterday’s press release, which can be found on the company’s website for disclosures about these measures and for reconciliation to the most directly comparable GAAP financial measures.

Now with me this morning are Chris Strong, President and Chief Executive Officer and Tina Castillo, Union Drilling’s CFO. I’d like to turn the call over to Chris.

Chris Strong

Thank you, Ben. Good morning everyone and thanks for joining us today. As you saw in yesterday’s press release our results for the third quarter of 2010 included revenue to $52 million, EBITDA of $6.2 million and a net loss of $4.4 million or $0.19 per share. Revenue grew by 19% over last quarter and this was matched by the improvement in utilization from 45% to 53%, so average day rate remained essentially flat.

The sequential increase in utilization was driven by higher activity levels in Texas and Appalachian. In Texas, we continue to put additional rigs to work out west with 13 rigs now drilling for oil. We also have two rigs drilling for NGLs in the oily part of the Barnett Shale in Montague County. Today 19 of our 20 rigs in Texas are currently running.

In Appalachia, we have 17 of our 32 rigs under contract while in the Arkoma Fayetteville Shale area work has been pretty steady all year and we have 11 of 19 rigs under contract today. That puts us at 47 rigs or 66% of the fleet on a rig count basis under contract today. Of course, we have the holidays, winter weather and the daily rig count bounces around some with maintenance activities and news, but the trend is clearly positive.

Most of the rigs that are currently under contract are the small single engine rigs with less than 750 horsepower in Appalachia and to a less extent Arkoma. With our continuing pattern of investing in higher horsepower rigs and upgrades to them, the disparity of rig values in the fleet continues to grow. In fact if you look at our utilization by rig value on our books or on a dollar weighted basis, those 47 rigs working today represent 94% of the company’s total rig PP&E book value. Much more of our capital is at work and it’s been reflected in utilization by rig count.

Our expanded safety program which we mentioned on last quarter’s call is going extremely well. We started with Texas and virtually every employee has been through multi day offsite behavior based training designed to enhance employee buy into a team oriented safety first culture. We are now in the middle of this program in the Arkoma and Exxon our largest customer following the XTO acquisition is sending most of their mid-continent field people we work with to attend the training with us.

I really see this training which enhances communication between people on the rig side complementing everything we already do with our safety programs to maintain the equipment and train employees how to use it. At this point, I’ll ask Tina to run through the financials.

Tina Castillo

Thank you Chris and good morning everyone. Revenues for the three months ended September 30, 2010 totaled $52 million or $14,994 per revenue day compared to revenues of $35.2 million or $17,592 per day in the third quarter of 2009. This 48% increase in total revenue is primarily attributable to the improvement in our utilization offset by the year-over-year decline in day rates.

On the last call, I mentioned that day rates might continue to decline by 5% to 10% from second quarter 2010 level. We are pleased that this decline did not materialize during the third quarter. Average day rates were essentially flat with the previous quarter. Later in the conference, Chris spoke about more directions to what we expect for day rate.

Operating cost for the third quarter totaled $39.9 million or $11,505 per revenue day, compared to $22.3 million or $11,167 per day in the third quarter of 2009. Sequentially, comparing our OpEx per day in the third quarter to the second quarter, we saw a decrease approximately $150 per day in spite of the additional costs we’re absorbing with respect to the expanded safety initiatives that Chris has mentioned and the full effect of wage restorations that we made in the second quarter 2010. As a point of reference, included in third quarter’s OpEx per day was approximately 1 million of startup cost for the last three rigs that went out to work in West Texas.

As Chris mentioned, we have 19 of the 20 available rigs working in Texas, so we do not anticipate any further material investments for startup costs. Drilling margin totaled 12.1 million or $3489 per revenue day compared to $12.9 million or $6425 per day for the third quarter of 2009. Compared to second quarter 2010 our margin per day improved by $131 or 4% increases. Although the increase is relatively small, it is notable that this is the first sequential increase in average drilling margin since third quarter of last year.

General and administrative expenses increased slightly to $6 million from $5.8 million a year ago. However, as a percentage of revenue SG&A costs are down about 500 basis points from a year ago and down about 200 basis points from last quarter. Essentially, we kept G&A expenses relatively flat, even though revenues have ramped up.

Third quarter EBITDA totaled $6.2 million in 2010 compared to $6.8 million in 2009. Compared to last quarter we saw an improvement of $2.6 million to our EBITDA while modest it’s certainly in the right direction. We recorded a net loss for the quarter of $4.4 million or a $0.19 per share compared to a net loss of $4 million or $0.17 per share in the prior year. Last quarter, we reported a net loss of $5.3 million or $0.23 per share.

For the third quarter we generated $10.7 million of cash flow from operation. The majority of that number approximately $9 million is a result of the tax refund from the IRS. However, we also to continue to invest in working capital as rigs have come back to work. Accounts receivable grew by approximately $7.4 million from June 30 to September 30.

We had $37.4 million drawn on our revolver as of September 30th compared to $28 million at June 30th. This June 30 we spent $19.6 million on CapEx which includes the new electric rig in Appalachia that we mentioned on our last conference call.

We made down payments for three (inaudible) which will be delivered in the next couple of months. We also incurred some costs associated with our new ERP system as well as made other rig enhancements and maintenance across our fleet.

Today our revolver balance is approximately $33.6 million or $3 million decrease over September 30th mostly attributable to the timing of customer collection and vendor payments. Our total CapEx budget for the year remains at approximately $60 million of which $51 million was spent in the first nine months of the year.

Our preliminary 2011 budget for CapEx is $36 million which includes one rig acquisition for the Marcellus to be completed in the first quarter of 2011 as well as the program to outfit more of the rigs with iron rough mix for safety purposes.

Our plan is to add two of these per quarter. We also have some recertifications and other necessary and normal maintenance activities planned. Looking at term contracts which we define as contracts standing at least 6 months or 6 wells, we currently have 22 rigs on term out of the 47 rigs working today. Since our last conference call, we have added 3 new contracts while 2 others have expired.

However, for both of those two rigs they are still working well to well for the same customers and we are in discussions with those customers to renew under multi-year contracts. We have 8 term contracts scheduled to expire in the fourth quarter and 11 in the first half of 2011. We believe that there are opportunities to renew several of those contracts at higher day rates, especially in the Permian. I will now turn the call back over to Chris.

Chris Strong

Thank you Tina. Looking ahead, I expect that we will continue to see improvement in our results, but the nature of that improvement is going to change. Up until now most of what we have seen has been driven by increased in utilization as we put idle rigs back to work. With 94% of the balance sheet value of the rigs already working, the pace of utilization improvement is likely to slow. However, there is room for margin improvement on the existing fleet and we have the financial flexibility to continue adding more rigs to it.

The 19% revenue improvement from the second quarter was mostly driven by utilization and came with some higher costs. Even with an improved overall rig count, there is room for a day cost to trend down some from what we have been experiencing particularly in repair and maintenance expense. I also think there are opportunities to move rigs especially in the Permian Basin. This is an area where rig count is rising and the demand for Barnett Shale style rigs built for horizontal work is growing.

Late last year we made the decision to redeploy rigs out of the Barnett to West Texas even though the rigs were basically only high enough to cover operating expenses and maintenance CapEx. We successfully positioned our equipment out there and customers are now more familiar with our name and the services we provide.

As far as improved results from additional investments are concerned, we will continue to spend CapEx on projects that upgrade the fleet and position it for higher returns. The three rigs, 10 top drives and 4 walking packages added in 2010 will improve the marketability of the fleet in 2011 and as Tina mentioned we are underway with another rig for the Marcellus that will be ready for service toward the end of the first quarter.

Well it’s too early to tell; I also think yesterday’s election results may provide more positive backdrop for our industry and the economy as a whole to prosper. That concludes our scripted remarks, Josh we are ready to open up the line for questions.

Question and Answer Session

Operator

(Operators Instructions)

Our first question comes from the line of Max Barrett with Tudor, Pickering, Holt. Please go ahead.

Max Barrett - Tudor, Pickering, Holt

Thanks, good morning guys. First question just on your, you mentioned the rig acquisition in Appalachia, just could you provide some specs on the rig and maybe the price you paid for it.

Chris Strong

Sure, actually we acquired a derrick and substructure with the electric rig that we bought and just put out in our (inaudible) and we are building a rig around that. It is going to be a 1000 horsepower mechanical rig with 1500 horsepower pump. The all in cost is going to be around $8.5 million.

We’ve looked at putting an electric jaw works on that rig and balanced out the cost, talked to the customer or actually there are couple of customers interested in it, but the delta on the price differential and the additional term we were going to require didn’t seem to be of interest. We are building a less expensive mechanical rig that will probably go out in the, either a 17 or 18 a day range.

Tina Castillo

Max, were you talking about the rig, the new rig that will be deployed in 2011 or the rig that we just completed and is working now?

Max Barrett - Tudor, Pickering, Holt

The new one in Q1 2011.

Tina Castillo

Okay.

Chris Strong

Yeah, that’s about $8.5 million.

Max Barrett - Tudor, Pickering, Holt

Just sticking with that subject, the prospect for additional new builds kind of in the, I guess, in the higher kind of the $17 million AC rigs. Talk to us about kind of the tightness in the market for that type of rig and maybe if Union is getting closer to doing something on that front?

Chris Strong

We’ve had a lot of nibbles, Max but it seems like there is a very healthy demand for shorter term contracts, lower capital cost mechanical rigs. That is where we are focusing some of our efforts.

I’d be pleased to build the $17 million AC rig, but I do not want to do it on a one year deal. If we are putting out rigs that may take a couple of more days to drill a well, but the customers getting the flexibility of not committing to term that seems to be a niche that needs to be filled right now.

Max Barrett - Tudor, Pickering, Holt

Okay, I guess, last question from me as it relates to day rates by region. If we take one of your larger 1000 or 1500 horsepower rigs, help us with kind of what day rate it could fetch in West Texas versus say Arkoma or Appalachia and are you seeing $20,000 day spot, day rates for any of your larger rigs?

Chris Strong

Not seeing 20 spot rates, as I said on my scripted comments, the Permian Basin in particular, six months ago we were putting rigs out in the, maybe not even in the low teens, 115 things like that. There is a lot of room out there because of how low rates were when things were just coming off the bottom.

We’ve had pretty healthy rates up in Appalachia with the Marcellus all the way through, but again mid to high teens kind of area on the mechanical. Even the mechanical doubles are getting those rates, affordable rates.

I have not seen north of 20. We’ve got some of our larger electric rigs that are still here in the Barnett that are north of that number. We have some of, one of our new builds up in Appalachia that which built in to a multiyear term contract (inaudible) about that number, but as far as re-pricing on existing rates in our fleet were not at 20 yet.

Operator

Thank you. Our next question comes from line of John Keller with Stephens Inc. Please go ahead.

John Keller - Stephens Inc

Just real fast, Chris you talked about upgrading a number of your rigs, iron roughnecks, top drives etcetera and I missed some of the numbers, but I go back to the call and get those later. How many of your rigs in general do you think are upgrade candidates as you look out into next year?

Chris Strong

Not a whole lot, John, I mean there may be a few more top drives we can do. Iron roughnecks is more of a safety item. They are not nearly as expensive as top drives which, the electric top drives are about $1.5 million, $1.7 million a copy; even some of the hydraulic top drives that Fresco builds now are north of a million. Iron roughnecks are a few hundred thousand a feet and I do not know that they really are something that improves the day rate opportunity, but it is just something that we need to do to reduce the number of fringed fingers and pans and so on.

I would say a lot of the upgrading that we can do has been done. We can still do more skidding systems and walking packages to the extent that we get paid for them. Top drives, really most of the rigs that we can put top drives on at this point have them. There may be a few more, but it’s not going to be a lot.

John Keller - Stephens Inc

Okay, and as you start to re-price this, maybe I’m just not quite clear on the direction as it flows through kind on a weighted average basis, as you sort of reprice some of these term contracts that are coming up in the next couple of quarters, I mean, do you expect that we can see kind of on an average basis, I mean, a fairly sizable uptick in kind of your rates and margins going forward, because I have got to think the what’s being worked off of right now is fairly low day rate low margin type of stuff that was really just supporting some of the utilization.

Chris Strong

Until there is more movement in Appalachia, I don’t know that we are really going to be pushing up like the 2000 or multi thousand dollar type increases. We may have some of those opportunities as I mentioned in the firm, you may not see that in the Arkoma that market has been fairly steady, I mean, we are getting some increases, but I don’t think they are as dramatic as perhaps people are expecting.

John Keller - Stephens Inc

Got it. One last, one kind of just more strategic or big picture if you will, but I mean there has clearly been a big differentiation in the market between larger, higher, more capable rigs and the lower ones, I mean we have all seen that trend over the last couple of years emerge. Is there a point, Chris where you feel compelled that may be you need to or from a competitive standpoint have to build a rig on spec or take that shorter term contract that you are sort of hesitant to take?

Chris Strong

Well, it’s funny you say that. I mean the rig we’re building for the Marcellus right now is essentially a spec rig. We don’t have a contract for it, so, there is so much telephone chatter and spring is coming. We want to have another piece of equipment ready to go out to work when the winter weather is behind us. We have to start now to have something really ready by the end of the first quarter.

Operator

Our next question comes from line of Andrea Sharkey with Gabelli & Company. Please go ahead.

Andrea Sharkey - Gabelli & Company

Hi, good morning. I was wondering, may be I am thinking about this completely wrong, but do you have the rigs that are lower horsepowers in Appalachia typically for shallow gas drilling? Will it make sense for, could you move those to West Texas to do some of the conventional oil drilling that I've been hearing has been going on there and or whether there might be some added demand or would that really not make sense from either in equipment standpoint or the cost to move it all the way there, what are the possibilities for that?

Chris Strong

Well, everything is bigger in Texas, Andrea. The rigs that are up in Appalachia have historically been drilling coal bed methane, Devonian shale may be down to 4000 feet or so. These are mostly single 800 horsepowers double derrick rig.

A lot of what you see there is drilling the conventional vertical work in West Texas is higher horsepowers, they are generally freestanding triple rigs as opposed to portable rigs that were running in Appalachia. There is not a lot of applicability.

Over time though one of the things that we are having to look at strategically is, will we be in the small rig business even if prices come back? The requirements cause the fleet to work for larger independence on the safety side, just the general overhead levels required to work for these kinds of customers may make us less competitive in the small rig market and that may be a part of the business that needs to be sold off at the appropriate time to smaller drillers that would work for the mom and pop independents.

Andrea Sharkey - Gabelli & Company

Okay, that makes sense. Maybe to follow on that line of thinking on the smaller stuff, you mentioned the Devonian, I know (inaudible) had talked about, maybe they drilled one or two wells there. Are you guys working for them before, people that might be looking to try to exploit some of that upper Devonian, is that actually coming back at all?

Chris Strong

Yeah, we are seeing a bit of that and actually we have about 7 or 8 of those small rigs out running, so it’s not as if there’s no business there. We actually are putting a small top drive on one of these lower horsepower power rigs to do some shallow horizontal drilling and we have done a good bit of that. We have four super single style rigs that have done horizontal coalbed methane.

The Devonian sale is something that Range is looking at, Equitable has done some horizontals in shallower field, some of the Marcellus. It’s certainly possible, we will see some of that. We don’t really have any impairment issues with the small rigs that are on our books for next to nothing at this point. The last count was, the 27 small rigs that are single engine 500 horsepower rigs are on our books for about $15 million.

We’re getting down to about $0.5 million per rig at this point. They can be put back in the field. There may be opportunities, but as I say it will probably have to be opportunities for customers that will pay up for a certain level of service and certain level of safety. There is probably the larger guys do, don’t want their new, their names splashed around in the newspaper if something happens on location.

Andrea Sharkey - Gabelli & Company

Absolutely. Maybe just one last sort of balance sheet question. I know Tina mentioned that the accounts receivable went up quite a bit sequentially. Was that just increased activity? Was there anything different going on there?

Chris Strong

Not really, I mean DSOs have trended up slightly, but it’s really driven by more billings.

Tina Castillo

I mean our revenues went up from last quarter about $13 million, our accounts receivable went up 7.4, our day sales outstanding is still hovering around 40, 45 days.

Operator

Our next question comes from the line of Victor Marchon with RBC Capital Markets. Please go ahead.

Victor Marchon - RBC Capital Market

The first question I have was just on the term contract pricing relative to the spot. Chris, any color you can provide on the terms or the contracts that are rolling in the fourth quarter and the first half of next year relative to where the leading edge pricing is? Essentially asking is the long-term contract rollovers going to continue to be a headwind or possibly a tailwind?

Chris Strong

Well, it’s a mix bag, but I don’t think we’re going to get hurt by it.

Tina Castillo

We have some numbers, primarily our strategy had been taking really 6 month terms because we didn’t want to get into too much terms, so much of what you’re seeing is some of the term contracts that we entered into April, May that are beginning to expire this fall and of course those in West Texas, we’re going do our best to get some rate increases.

If you are asking do we still have some of those 2008, 2009 term contract on our books, we still have a handful, but a lot of what we’re going to be seeing begin to roll over are the ones that we have entered into early 2010 and so we would expect to have some headwind.

Chris Strong

Yeah, you got a couple that are the 24,000 a day type rigs and then you lose one of those, but as Tina said we resisted really being termed up very heavily earlier in the year and we’re trying to keep it into six month deals because you don’t want to term up with at bottom. You lose say a 24 type rig goes down to 19, and then you have got 3 of the 3 or 4 that go up 1500 bucks may be it’s a push.

Andrea Sharkey - Gabelli & Company

Chris, you had mentioned the Permian specifically on a day rate of 11-5 about six months ago. Where are we at now on leading edge pricing for per equivalent type of rig?

Chris Strong

Its getting differentiated out there Victor. We got a lot more appetite for the Barnett Shale rigs I was talking about, that already have the top drives and are set up for deeper horizontal work. You are seeing the lot of interest in that horizontal oil drilling further west of Midland, Pecos, Reeves even over to we are in New Mexico.

That equipment is pulling the way. You probably be seeing, I don’t know, whether 15 to 16 is possible in those rigs. We have some older triples that are not set up right now for that drilling. That are really in and around the Midland area, doing more, what has been common out in the Permian Basin a lot of vertical and directional work that doesn’t require that much sophistication.

Those rigs are going to come up as well in price, but I don’t think they are going to come up as nicely as the rigs with higher capital devoted to them in better parts and better circulating systems and path drives essentially.

Victor Marchon - RBC Capital Markets

On operating costs, you guys had talked about some of the costs incurred the last few quarters going away. How do we think about operating costs on a per-day basis looking out into the fourth quarter and during 2011?

Chris Strong

Well, I keep thinking, we’re going to see some benefits there because 115 a day is an average just feel too high and we have had as Tina mentioned very quantifiable start-up costs, safety program costs, and things like that.

We’re going to see some what less of that. We keep saying start-up costs are behind us, but at this point really most of the fleet is out there. As I said, on a PP&E basis is almost everything its running. I would hope to see a trend down. I don’t know if there is $500 a day quarter-over-quarter of potential. I don’t think its going to be a huge amount. I am not looking for $1500 a day of reduction, but that some of the costs should come in on the R&M side.

Tina Castillo

Yes, the other thing that we have to watch as well as we look at 2011 in West Texas is the labor that’s out there. In our budget models and talking with the guys out there, we have got a higher wage increase projected, then we might in the other two areas and so that that will be something that we have to carefully monitor.

I’d agree with Chris to the extent, that we are not going to see giant lead for $1500 per day, but we would expect for it to trend down. We have FRC that’s out there. We are continuing to focus on our safety initiatives and it should go down, but not leads.

Chris Strong

The FRC we are thinking flame retardant clothing is being mandated by OSHA on all the rigs. We’ll have to see a place out, but we are looking at something that might be in the range $40 a day for that additional cost. We have most of every time track we have though as reopeners for any kind of significant labor increases.

It seems right we could see that out in the Permian if there, saying we might go from 300 to 400 rigs out there, I’m not sure where the people come from and that usually drives up salaries and wages.

We have already seen typical improving cycle poaching of rig managers become consultant or directional drillers that’s all in full swing out there right now.

Tina Castillo

Victor, I mean we’re heavily focused on our OpEx as we are pricing OpEx certainly in area, where we monitor and got to control, so that is definitely a focus area for us.

Operator

Our next question comes from the line of Jud Bailey with Jefferies & Company.

Jud Bailey - Jefferies & Company

A few more follow-ups here on, what's going on in the Permian and your rig rollovers? First, on your breakout for your rig count in Texas, I apologize if I missed this, where you went through your stats earlier, but did you say, of your 20 rigs in Texas, what's the breakout between, what's in the Permian and what's in the Barnett?

Chris Strong

Yes, 13 out in West Texas. We got a couple rigs up in Montague County on the Oklahoma line that are drilling for oils in the oily part of the Barnett. The balance of the 19 that are running here in the Barnett has been basically under on track.

Jud Bailey - Jefferies & Company

What's in the Permian, can you give us just a little sense, a little more color on the composition there? I mean, you mentioned some of the bigger Barnett-style rigs that you have out there, but also you have smaller. What's the mix within the Barnett itself on what's working there?

Tina Castillo

In the Barnett or in the Permian?

Jud Bailey - Jefferies & Company

I’m sorry in the Permian.

Tina Castillo

We have about half and half the 1000 horse power or greater and the other ones would be less than 1000 or so.

Jud Bailey - Jefferies & Company

That's helpful. The ones that are in the Barnett, do you anticipate those staying there, or do you think you'll probably wind up moving those over to the Permian? I know you said a couple are actually drilling for oil targets, so maybe those stay there, but do you think you would move the others over to the Permian, or maybe even would there be demand in the Eagle Ford for those units?

Chris Strong

Possibly because a lot of what we have like the couple of the larger 1500 horse power ideal rate so one there up in Montague doing the oily Barnett. We have generally larger more sophisticated equipment that remain in the Barnett. These are some of the high dollar term contracts that we are still running off.

Jud Bailey - Jefferies & Company

Of the 22 term contracts, do we assume most of those are in Texas, or are those in Appalachia, or can you give us some color there on where those term contracts are geographically?

Chris Strong

They really spread. We got some in Fayetteville. We have got some up in Appalachia and some here.

Tina Castillo

Well, I can say that four of those 22 are in Arkoma and then between Texas and Appalachia they are split evenly.

Operator

(Operator Instructions)

Our next question comes from the line of Conor Ryan with Deutsche Bank.

Conor Ryan - Deutsche Bank

I was just wondering if you could perhaps give me a little bit more detail on the CapEx budget for 11. What was the total number again, and then how was that going to be split up between rig acquisition and safety, etcetera?

Tina Castillo

Well, we have $36 million total CapEx budget of which $8.5 million is for that new build in the Marcellus. We have about $3 million for those iron roughnecks. We got a lot of our customers asking for five-inch drill pipe so there is probably about $6 million, $7 million of that CapEx budget allocated for five-inch drill pipe and then the rest is just normal maintenance pipe stuff. We have some 1600 mud pumps that are customers asking for in the Marcellus. Those are some of the key things that I can think of off top of my head.

Chris Strong

That’s what we know right now. This is not a sealing. If we have customer demand and the economics look good to us, we've got plenty of financial flexibility, and there's no issue raising the CapEx budget to acquire build additional rigs, is the economics make sense to us.

Conor Ryan - Deutsche Bank

Yes. On that front, I mean, in years what paybacks do you guys shoot for?

Chris Strong

Generally shoot for 30 years. Some of the adders, so to speak, have had better economics, sometimes top drives, walking systems, the reason you do a lot of those things, which are down $1 million, $2 million enhancement to mud pump upgrade things like that, that you can get incremental day rate and additional turn him on contracts often the payback some those upgrades come in at year and half to two years as oppose to say new build where you are working for three or maybe a stretch of that a little future.

Operator

Management I have no further questions in the queue. I will hand it back for any further remarks.

Chris Strong

Well, thank you all for your continued interest in Union Drilling and we look forward to speaking with you after the year’s results are finalized. Good bye.

Operator

Ladies and gentleman that does conclude the Union Drilling’s third quarter earnings conference call. Thank you for your participation and you may now disconnect.

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THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

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Source: Union Drilling CEO Discusses Q3 2010 Results - Earnings Call Transcript
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