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Executives

Chris Strong - President & Chief Executive Officer

A.J. Verdecchia - Chief Financial Officer

Ben Burnham - Investor Relations, DRG&E

Analysts

Jud Bailey - Jefferies & Co.

Steve Ferazani - Sidoti & Co.

Kevin Pollard - J.P. Morgan

Mark Brown - Pritchard Capital

Jeff Tillery - Tudor, Pickering & Holt

Victor Marchon - RBC Capital Markets

Mike Breard - Hodges Capital

Union Drilling Inc. (UDRL) Q4 2008 Earnings Call March 6, 2009 10:00 AM ET

Operator

Ladies and gentlemen, thank you for standing by, and welcome to the Union Drilling Incorporated, fourth quarter 2008 earnings conference call. At this time all participants are in a listen-only mode. Later we’ll conduct a question-and-answer session and instructions will be given at that time. (Operator Instructions)

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

Ben Burnham

Thank you Patty and good morning everyone. We appreciate you joining us for Union Drilling’s conference call today to review fourth quarter 2008 results. Before I turn the call over to management, I have the normal housekeeping 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 March 13. 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, March 6, 2009 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 will, 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 that out of the way, with me this morning are Chris Strong, the company’s President and Chief Executive Officer and A.J. Verdecchia, Chief Financial Officer.

Now I’d like to turn the call over to Chris.

Chris Strong

Thank you, Ben. Good morning everyone and thank you for joining us today. Operationally we had a solid fourth quarter, revenues totaled $81 million and EBITDA came to $19 million. Excluding a non-cash charge for the impairment of goodwill which A.J. will discuss in a minute, net income was $4.25 million or $0.19 per share during the quarter. Utilization of the fleet was 69.4%, up from 61.6% in the same period in 2007, but down sequentially from 73.8% in the third quarter of 2008.

We typically have a decline in activity during the holiday season that negatively impacts utilization for the fourth quarter. However, the decline in utilization we experienced in the recent quarter also marked the beginning of a massive erosion of demand for land drilling services in the domestic market. I’ll talk more about how that’s impacting us and what we are doing about it in a few minutes, but first a few updates and highlights from the fourth quarter.

While I’m clearly not happy with where the stock price has been trading over the last several months, the upside is it represented an attractive investment opportunity for the company. During Q4, we repurchased approximately 1.7 million shares under our share repurchase authorization. Subsequent to the end of the quarter, we completed the balance of our authorized $2 million shares repurchase. In total we spent $10.5 million, for an average of $5.23 per share including commissions.

As stated in the press release, we essentially bought nearly 10% of the company for less than the price of a new rig. Given that we have no plans to build additional rigs in the present environment and given this company’s strong balance sheet, we’ll continue to evaluate share repurchases as a potential use of free cash flow going forward.

As discussed in the last call, we are adding four rigs to the fleet that will be operational in the very near future. We have a walking rig dealt for pad drilling in the Barnett shale that is going out in the field next week with a two year term contract. We’ve had some delays on critical components for the two electric rigs being build for the Fayetteville, but I expect the first rig will be delivered at the end of the first quarter and second later in April. These rigs also have two year term contracts.

We have owned fourth rig for sometime, but it is not been in our active rig count. It is a 1000 horsepower portable rig that we have refurbished and equipped with new pumps and a top drive for horizontal drilling in the Marcellus Shale. It should be in the field by the end of this quarter and has a contract for ten horizontal wells, which should take the remainder of 2009 to complete.

So, in total we’re adding four rigs to our fleet. By next month or so we shall bring our rig count to 75. If there is incremental demand for more equipment in the Marcellus, we do have two telescope and trailer mounted rigs in Arkansas, that have large enough draw works in direct capacity for horizontal drilling in the Marcellus.

While we would have to reengineer the substructure and carrier to comply with the requirements in the Northeast, these rigs could be modified for this work at a far less cost than new rigs. In order to undertake these improvements, we would need sufficient dayrate and contract covered to provide a return on the invested capital.

Now, I’ll turn the call over to A.J. to run through the numbers, before I finish up with some comments about the current environment and what we’re seeing for 2009.

A.J. Verdecchia

Thanks Chris. Revenues for the three month ended December 31, 2008 totaled $80.9 million or $17,837 per revenue day, compared to revenues at $67.4 million or $16,753 per day in the fourth quarter of 2007. The increase in revenues was partially driven by higher utilization. Additionally we booked $3 million in revenues related to early termination payments from a drilling contract.

Those who have followed Union Drilling for a while may recall that we signed a contract in late 2006, turning the five rigs out of the Rockies, down to the Fayetteville Shale to work for one customer. Shortly after that move, we announced that our customer had not experienced the geological results we anticipated in the shallower parts of the Shale and we’re looking to reduce the scope of their original commitment.

The $3 million we booked in the fourth quarter represented the remaining payments for lost margin due to the reduced size of their contract. The impact on revenues increased our reported average revenue per day by $662.

In accordance with an agreement for payment of the remaining $3 million, we received $1 million at the end of January. At the beginning of this week, the customer filed for Chapter 11 Bankruptcy protection. As a result of the subsequent event, we took an additional charge of $2 million through G&A as bad debt expense.

Operating costs for the fourth quarter totaled $51.3 million or $11,306 per revenue day, compared to $43.9 million or $10,920 per day in the fourth quarter of 2007. The increase reflects the higher labor expenses and increased material costs, especially for steel products and fuel. About two thirds of these higher costs were associated with our internal trucking and mechanical support departments; the remaining third was related directly to rig operations.

Drilling margins per revenue day averaged $6,531 for the fourth quarter of ’08, compared with the fourth quarter of 2007 average of $5,833. When you renew the effect of the contract termination revenue, year-over-year margin was essentially flat.

General and administrative expenses increased to $10.7 million, compared to $5.5 million in the previous year’s fourth quarter. Approximately $4.3 million of the fourth quarter G&A expense was due to bad debt as a result of several customer bankruptcies. As I just mentioned, $2 million out of this $4.3 million in bad debt was from the same customer that we booked contract termination revenue for, in the fourth quarter.

We are continuing to aggressively monitor receivables on our books as we tighten standards for extending credit to new customers. We are prepared to keep rigs idle rather than sent them out to work for companies with questionable financial strength, who are unwilling to prepay for services.

Fourth quarter EBITDA totaled $19.3 million in 2008, compared to $18 million in 2007. EBITDA excludes a one time non-cash charge of $7.9 million for the impairment of goodwill. We will require to take this charge due to the decline in the market value of the company below book value. All of the goodwill was associated with our acquisition of Thornton Drilling back in 2005.

Depreciation and amortization for the quarter totaled $11 million, up from $10.5 million last year, but down from $11.6 million in Q3. The sequential decrease in the fourth quarter was due to several of our smaller rigs in Appalachia, reaching the end of their depreciable lives for book purposes.

In total, our pretax income was $162,000; income taxes were $3.9 million. To properly calculate their effective tax rate, you need to add back the goodwill impairment to pretax income. Excluding this charge, our effective tax rate for the quarter was 48%. Our effective tax rate for the year, again adjusted for goodwill impairment was 44.6%.

Moving to the bottom line, we reported a net loss for the quarter of $3.7 million or a loss of $0.17 per share. Excluding the goodwill impairment charge, net income was $4.2 million or $0.19 per share, compared to $3.9 million or $0.18 per share in the fourth quarter of 2007.

On the balance sheet, we had $42.6 million drawn on our revolver as of December 31. That number is currently $47 million as of today, which reflects payments on our new rigs, as well as the completion of our share repurchase authorization. Total long term debt as of December 31 was $45 million.

Capital expenditures for the fourth quarter totaled $27 million, of which $13 million was designated as maintenance CapEx. The remaining $14 was for progress payments on the new rigs. As of year end, we had $19 million of CapEx remaining to complete the construction of the four new rigs.

As of today, we have about $12 million remaining to complete these rigs. During 2008 we spent $45 on maintenance CapEx. We have taken steps to defer maintenance CapEx, so the 2009 amount should be less than half of the 2008 number for maintenance CapEx.

I will now turn the call back to Chris.

Chris Strong

Thank you A.J. Since you are all aware by now, things in the drilling rig market are pretty ugly. Baker Hughes U.S. rig count has declined by over 39% since its peak in September of 2008 and the pace of this decline is faster than those experienced in 1982, 1997 and 2001. While the vertical rig count started to come down earlier, the horizontal component is coming down rapidly as well. That’s a positive, since there’ll be fewer high IP rate wells brought online and supply will come down more quickly.

In our backyard here in Fort Worth, we had a peak of 214 rigs drilling in the Barnett Shale in October and are under 100. My expectation is that even with reduced natural gas demand; the rig count contraction will overshoot on the low side and set the stage for a recovery in 2010.

Following the holiday shutdown in December, many of our rigs were not under contract or ideal. Our utilization in the first two months of the first quarter was a little below 50%, and as of yesterday we had 30 rigs running or 42% utilization. In most cases right now, day rate reduction is not going to drive higher utilization. Customers are shutting rigs because even significantly lower service costs won’t do enough to provide a positive return with current commodity prices.

In the case of term work; the drilling rig maybe the only service and operator uses that has a term contract, so paying out the contract may make better sense from the cash flow standpoint. We are currently engaged in some of those conversations, but have not entered into any early termination agreements for rigs that are currently under term contract.

At the moment we have 19 rigs under term contract, excluding the four rigs that are going into service in the next month or so. This gain will be offset by four rigs reaching the end of their contracts during the second quarter and there are three more rigs reaching the end of their contracts in each of the third and fourth quarters. The balance of the remaining contracts roll off in 2010.

In response to the drop in activity, we have undertaken a number of initiatives to reduce costs. Labor is our single highest expense and we’ve reduced our work force inline with utilization declines. When a rig goes down, the people on that rig are being laid off. Unlike last year, there are no projects in the yard to keep a crew busy until more work for the rig is found.

We pushed through across the board salary reductions in some areas on the order of 15% and we’ll be looking at additional salary and wage reductions. Given the lower rig count, we’ve also had to make cuts in the support areas like trucking and mechanics, as well as in the administrative overhead.

As I mention last quarter, we’ve consolidated our procurement function under our director purchasing. Centralizing this function has led to the removal of purchase order books from the drilling rigs, and we are implementing lower approval thresholds across the company.

We are deferring maintenance on our idled rigs and substantial cuts have been made in contract labor such as welders and when appropriate we will also cannibalize parts from idled rigs for use on working rigs, rather than purchasing additional equipment.

Having been with the company for about 10 years now, this is not new. 1999 and 2002 were both years we’re managing for cash rather than net income or EBITDA was the main focus, and I expect 2009 to be much the same.

Peak to trough in those two prior downturns averaged about a year, and the retracement back to the prior peak averaged about two additional years. Given the pace of the current decline, I hope this cycle with time will more be a bit more compressed.

With that Patty we are ready to questions.

Question-and-Answer Session

Operator

Thank you, sir. (Operator Instructions) and our first question comes from the line of Jud Bailey from Jefferies and Company; please go ahead.

Jud Bailey - Jefferies & Co.

Chris, question on your margin per rig day going forward, you said I believe that your utilization is obviously down since the beginning of this quarter. How do we think about margins with some of the rigs you’re letting go, I presume are some of the lower margin rigs that you have in your fleet? How should we think about margin decline during the next couple of quarters?

Then again on utilization, as we go into the second quarter, we usually see some sort of a seasonal increase in Appalachia. Do you think that occurs this time and if so can you give us a sense maybe of the magnitude?

Chris Strong

Jud, I’d say on the margin question, what we’ve seen in the past with these sorts of slowdowns will probably occur again, especially with the term contract cover being on the higher dollar rigs that have the higher day rates. You’ll probably see the margin per rig operating day expand, since the smaller rigs with lower margins are the ones that are disappearing out of the utilization number.

As far as Appalachian goes, its kind of a “we’ll see.” I mean we’ve had some demand for the smaller rigs to do vertical Marcellus wells, where customers want to hold the acreage, they’ve spent a lot of money up there, but maybe they want to defer the costs of the direction of drilling crew and the multi-stage frac.

So, there is some exploratory work being done with vertical rigs that might give us a little help up there. Some of the other vertical plays up there that we’ve been involved with for a longtime, they do work at lower prices and there is a bit of a premium up in the Northeast related to the higher BTU content of the gas and lower transportation cost to market.

So that really remains to be seem, but we have a good bit of the smaller part of the rig fleet up there that is idle, just with the normal sloppiness at the end of winter and cross flaws.

Jud Bailey - Jefferies & Co.

Okay and if I could just follow-up; just to clarify, you think your margin per rig day, did you say it could go up from where it was in the fourth quarter?

Chris Strong

I think that’s normally what’s happened in the past Jud, where if we have a slowdown the spot rigs generally has commended lower margins, so that the margin per rig operating day as the utilization declines, probably will go up.

Jud Bailey - Jefferies & Co.

Okay and my last question will be the four rigs that are coming online this quarter; will we assume that the margin per rig day on those are higher than the average for the fleet?

Chris Strong

Yes, I mean those deals were contracted for over the summer, back in the hay day of higher oil prices, so those were negotiated; pretty much likely negotiated at the other deals that there’s sufficient contract cover, to provide a kind of EBITDA multiple return on cash. We’ve looked at sort of three times cash flow, so in the case of the two year contracts we’re not going to get the entire value of the rig back in the two years, but it was kind of three times EBITDA economics.

Operator

Thank you and our next question comes from the line of Steve Ferazani from Sidoti & Company; please go ahead.

Steve Ferazani - Sidoti & Co.

A very good morning, Chris, A.J. You mention the potential of termination of long term contracts, any renegotiations of day rates on the long term contracts?

Chris Strong

We haven’t seen renegotiation at this point Steve. Well, let me back up; we do have a large customer where we’ve had some of those concessions made over the term contracts to keep additional rigs that don’t have any term contract cover continuing to run. Those day rate decline have been fairly nominal, but if I have to take a little bit of decrease on a termed up rate, to keep a couple of other rigs that are in the spot market running, I think that’s a reasonable deal; that’s kind of a one off situation.

On the contract termination, as I said we’re having some discussion there. It’s probably at the level of, make go on the margin that we’ve been earning plus some sort of component for demobilization of the rig. That would make us hold as far as the cash flow we were expecting to receive from the rig over the remainder of the contract plus the termination provisions that are in the contract at the end for demobilization of the rig.

Steve Ferazani - Sidoti & Co.

Okay; on the CapEx, did you throw in a ’09 number and do you have any kind of breakdown of where it’s going?

Chris Strong

We did not throw out a ’09 number; expect that at this point we’ve got about $12 million. Even though the rigs are said to deliver fairly quickly, there’s some overhang in payables of components that we have not paid for yet, so that’s the $12 million balance on the new build CapEx if you will.

I think A.J. had mentioned, we were north of $40 million from maintenance CapEx last year. Than number included a lot of upgrade projects if you may recall, we did about four new draw works on rigs, new derricks, some major upgrades on rigs with pumps, derricks and draw works for the longer reach horizontal drilling in the Barnett primarily. Those obviously will repeat and with a much lower rig count, the other $40 million number probably is less than half of that in 2009.

So, borrowing any one off deals for incremental CapEx up in the Marcellus, which is probably the only market where I would see it happen. I mentioned the possibility we might take a couple of our telescope and trailer mounted rigs out of Arkansas up into the Northeast, I mean that incremental CapEx would only be if we had term contract cover to provide a return on that capital to us.

Operator

Thank you and our next question comes from the line of Kevin Pollard from J.P. Morgan, please go ahead.

Kevin Pollard - J.P. Morgan

Hey, good morning Chris.

Chris Strong

Good morning Kevin.

Kevin Pollard - J.P. Morgan

I wanted to follow up on Joe’s question regarding the margin as the mix of all. You drop a lot of the spot market rigs. The utilization number of you gave us, it looks little close to probably two thirds of your rig we are working now or rig that are on term. So, I guess my question is kind of a two part question. First of all is, if you have the four rigs expire in the second quarter and the three rigs lead to the subsequent quarter, would you expect those rigs to go idle as well, based on kind of the lack of demand we’re seeing out there?

Chris Strong

As of today I’d say yes, but I don’t know if the rig count can keep falling by 50 rigs a week forever I mean at some point you get to a bottom, but again as of today their decision has been out there. It doesn’t matter if you say “Well, it’ll come down $4000 or $5000 a day.” Well that’s obvious that people are saying, “Hey I’d rather pay you off to get out of the term contract,” those people are not actively looking for rigs in the spot market.

Kevin Pollard - J.P. Morgan

So, I guess my question then, my follow-up question that is, is Q1 we’ll probably see some flat or maybe even slightly improving margins as the mix shift towards term contracts, but it seems like at this point most of the spot surface is pretty close to idle and so as we go into Q3 and Q4, if those rigs rolling of term do in fact go idle, do you start to see the margin come down at that point since those rigs presumably have pretty decent margins in the contract?

Chris Strong

Well, it just depends how it plays out. Obviously, right now we’ve got as you said two thirds term and one third spot. If the one third spot disappears, then all you have left is term. Your margin per day is going to be pretty high, even if your absolute dollar cash, your dollar margin for the company is going to be quite a bit lower, but the remaining rigs on term contracts are rigs that are generating often margins north of 10,000 a day.

Operator

Thank you and our next question comes from the line of Mark Brown from Pritchard Capital; please go ahead.

Mark Brown - Pritchard Capital

Hey Chris, I was wondering how many customers did you have bad debt issues. I know you mentioned a lot of it was from the Rockies to Fayetteville customer there, but how many total, the number of customers?

Chris Strong

The bulk of it Mark is, we got hit with four bankruptcies primarily in the fourth quarter where we took the hit and fairly, in each case, reasonably well capitalized companies that we had a history of doing business with and made pretty good money with. That’s the bulk of it, its four bankruptcies.

Mark Brown - Pritchard Capital

Okay. Do you have any update in terms of on the revolver what your peak trough expectation is?

Chris Strong

It’s probably mid 50s. We said about 47 today just post payroll. That cycle is up and down, so if we have 12 remaining to fund on the new rigs going into the market, that will be offset by some cash coming in over time as the payables go out. So, it might peak in the mid 50s, reasonable guess.

Operator

Thank you and our next question comes from the line of Jeff Tillery from Tudor, Pickering & Holt; please go ahead.

Jeff Tillery - Tudor, Pickering & Holt

Hi, good morning Chris.

Chris Strong

Good morning, Jeff.

Jeff Tillery - Tudor, Pickering & Holt

On the last conference call you gave a $50 million on gross margin that was contracted for ’09. I assume nothing’s been added to that. Is that still a decent number for what’s covered under contracts for 2009?

Chris Strong

It’s probably come down a little bit, but not a lot. As I mentioned a little earlier Jeff, we have made some concessions on some of our term rigs where we have a customer that we’re running a lot of rigs for that said “Hey, help us out here and we’ll keep some of these other rigs and crews active, that don’t have term contract covered” so the number has probably comedown a couple of million as a result of that.

Jeff Tillery - Tudor, Pickering & Holt

Okay, that’s helpful and then I would assume if there is no recurrent on the bad debt expenses, is there anything unusual in the G&A number in Q4, where there is a kind of a whether your at less $4 million on the run rate we should expect going forward?

Chris Strong

Well, it just depends how severe things get. Obviously, we will look at reducing the G&A component just as we’ve looked at reducing operating expense head count. If you’re running a much smaller company, you’re going to look for cuts in those areas as well.

Jeff Tillery - Tudor, Pickering & Holt

Okay and I think this question was asked earlier, but seasonally as you get out of winter, we typically see some activity increase in Appalachia? What point would that normally be occurring? Are we there yet and are you seeing kind of any up tick in the traditional, kind of convention Appalachian truly?

Chris Strong

Well fortunately we’ve had a pretty solid cold winter up there or else we’d be in a lot of worse trouble right now as far as the storage situation. So, that’s something that hits us if you have colder than normal winter up there; things gets pushed out a little further until folks normally get their joined programs going. Especially with the smaller rigs that have to move very frequently, a lot of that is much more efficient after the snows melt and the rainy part in April gets behind us.

So, I would estimate that if we’re going to see some rebound in the shallow drilling, which really does have pretty low SMD costs, so I wouldn’t be surprised to see some of that comeback, where those numbers can work at $4 gas. So, you may see some rebound with the vertical rigs up in Appalachian, as we get into the middle of the second quarter.

Jeff Tillery - Tudor, Pickering & Holt

Okay. Thank you very much.

Operator

Thank you. (Operator Instructions) Our next question comes from the line of Victor Marchon from RBC Capital Markets; please go ahead.

Victor Marchon - RBC Capital Markets

Well thanks, good morning. Just most of my questions have been asked. So, I just to want see if you guys provide any guidance just on how we can look at DDNA and the tax rate for ’09?

Chris Strong

I think the tax rate in Q4 is probably a fairly decent indication of what we could see going forward. In terms of DDNA, I mentioned that we did have that drop-off in our run rate of depreciation because of the order assets that had reached the end of their life, and if we continue to decrease the maintenance CapEx, we shouldn’t see depreciation increase, because the rigs that are reaching the end of their life is probably higher than the new rigs or new equipment that we’re adding to the depreciation run rate.

Victor Marchon - RBC Capital Markets

So using fourth quarter as a good run rate going forward and keep that relatively flat through the year?

Chris Strong

Based on what we have right now.

Victor Marchon - RBC Capital Markets

Okay and just a second one was on the availability on your credit facility today. I think Chris you had mentioned that it could peak out the mid-50s. What will be the availability off of that number?

Chris Strong

Well its $97 million revolving line of credit that matures in 2012. We have about $5 million of letters of credit on it. So, we got a little over about $40 million, $45 million of availability to-date.

Victor Marchon - RBC Capital Markets

Last one Chris, you had mentioned, looking at additional share repurchases, I just wanted to see what the thoughts were from an M&A standpoint. Is that still far in to the future as you guys are taking a look at buying up some assets or can you just sort of speak to what you are seeing in the market there and what your appetite is today and when it can potentially increase going forward?

Chris Strong

Well, certainly we have to talk to our Board about this, which we have a Broad Meeting coming up next week. My sense from looking at the historical trends Victor is that, the stocks tend to bottom ahead of the rig count bottoming and if something is to be done there, it probably makes sense to look at it sooner rather then later.

Then as far as distressed assets, clearly the recovery in cash flows take quite while, even if the rig count bottoms and you’re starting to crawl back out of the bottom; you don’t have much pricing power; rig count maybe climbing, but you’re not going to be having a lot of cash flow. So, probably the distressed asset opportunity is out there a good bit longer. So we’re certainly going to chat about all those things next week and no real decisions have been made at this point.

Victor Marchon - RBC Capital Markets

Thank you.

Chris Strong

You’re welcome.

Operator

Thank you and our next question comes from the line of Mike Breard from Hodges Capital; please go ahead.

Mike Breard - Hodges Capital

You said your utilization now is about 42%. I wonder if you could give us an idea of how many rigs your working in the various areas, the Barnett Shale, Appalachian, just to get an idea of where the drop in utilization is coming from.

Chris Strong

Well, right now the severest drop has been in the Arkoma Basin area, including the Fayetteville Shale. Appalachian and Texas are a bit higher; that’s not really surprising to me and that the Arkoma Basin is an area where we have invested relatively less money than in Texas and the Barnett Shale.

A lot of our newly larger rigs in Texas are under term contract and are holding up better; the Fayetteville Shale we have proportionately a higher amount of older smaller rigs, some of which have continued to do the traditional Arkoma Basin and Hartshorne coal drilling, so that has really surprise me and Appalachian is holding up in-part because of a lot of activity with the emerging Marcellus Shale play.

Mike Breard - Hodges Capital

Okay, but pretty much more depends on the customer whether in the area of actually having all kind of cuts back, it doesn’t matter whether the rigs are working?

Chris Strong

Well, I’d say we’ve seen more of a trend in activity up in the Northeast, that there are a lot of customers up there that have spend money on acreage in the Marcellus and whether it is that they want to hold leases, that they want to drill at least to get some additional science and understand a little better what their acreage position is and where to drill aggressively when the prices rebound, I’m not sure; but regionally I think that market has held up better.

Yes, there is certainly customer specific issues, where depending on whether our customer was out spending its cash flows and has to pullback its CapEx to a greater percentage than the next customer; you are seeing variations in cut backs by customer, based on their own financial conditions.

Mike Breard - Hodges Capital

Okay. Just one quick question; I know that’s much too early to be asking this, but when things eventually do turnaround and demand picks up, how long would it take you to put your rigs back to work and then could you be at a 65% utilization rate within a matter of months or how long you think it might take just to get your rigs back in the field?

Chris Strong

I don’t thing that’s unreasonable. Clearly there is a huge amount of labor on the side lines. The initial recovery phase, there’s a lot of experienced labor available. It’s really once you get closer to retracing back to the prior peak, where labor gets more difficult. Also those are the areas where you start to find bottlenecks, because in the downturn if you need drill pipe on a running rig, you’re going to get it from the yard, from a pipe rack that was dedicated to a rig that’s not running.

So, we saw that some of this as a big ramp up a couple of years ago, where there were a lots of bottlenecks as far as engines from Caterpillar, drill pipe was very hard to come by and was 12 to 18 months out to get new drill pipe. So, as the industry uses up assets off of rigs that are idle to conserve cash, those rigs are harder to put out, because they often require capital to address the different maintenance issues, but my guess is you get out a good chunk of the rig fairly easily and fairly quickly.

Then at the margin, again rigs that you’ve borrowed assets from, essentially it may take longer to get out and it’s usually those last few rigs or last 20% of the fleet, something like that, that is harder to crew up and you may encounter delays in accessing the supplies and materials you need to address the deferred maintenance.

Mike Breard - Hodges Capital

Okay. Thanks very much.

Chris Strong

Welcome.

Operator

Thank you (Operator Instructions) Our next question comes from the line of Mark Brown from Pritchard Capital. Please go ahead.

Mark Brown - Pritchard Capital

Hey Chris, I was just wondering if you could tell us how many rigs you have in each of your three major areas, currently actively drilling?

A.J. Verdecchia

Well, we said we have 30 rigs running today and of that 15 in Appalachian, and Chris was saying less utilization in Arkoma, seven and Arkoma and nine in Texas, mainly in the Barnett.

Mark Brown - Pritchard Capital

Okay, and just the other question I had is, how are you thinking about potentially scrapping some of the lower end rigs. Just what are the economics used to make that decision and what’s the timing of when you think that might, if it were to happen that might still happening?

Chris Strong

Yes, I think a lot of these rigs have run recently and that there probably will be work for them. However as A.J. said, quite a few of these rigs have reached the end of their depreciable life. So, it’s not like we’ll take any significant hit if we elect to decommission some of them. That’s something we haven’t really gotten into.

If the market stays like this for a while, I’m sure our auditors at Ernst & Young will have that same conversion with us on whether we not only on rigs that have been fully written-off, but on some of the other rigs to address future potential impairment beyond the goodwill.

Operator

Thank you and I show that we have no further questions at this time. I’ll hand back to management for any further remarks.

Chris Strong

Well, thank you all for joining us today. I appreciate your interest in Union Drilling and we’ll be back on the line in another six weeks or so. Thank you.

Operator

Ladies and gentlemen, that does conclude our conference for today. Thank you for participation. You may now disconnect.

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Source: Union Drilling Inc. Q4 2008 Earnings Call Transcript
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