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Executives

Ben Burnham - DRG&E

Chris Strong - President and CEO

Tina Castillo - Controller

Analysts

Steve Ferazani - Sidoti & Company

Max Barrett - Tudor Pickering & Co.

Andrea Sharkey - Gabelli & Company

Victor Marchon - RBC Capital Markets

Union Drilling, Inc. (UDRL) Q1 2010 Earnings Call May 5, 2010 6:00 AM ET

Operator

Good day, ladies and gentleman. Thank you for standing by. Welcome to the Union Drilling’s first quarter 2010 Earnings Conference Call. During today's presentation, all parties will be in a listen-only mode. Following the presentation, the conference will be open for questions. (Operator Instructions) This conference is being recorded today, Wednesday, May 5th, 2010.

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

Ben Burnham

Thank you, Jamie [ph] and good morning everyone. We appreciate you joining us for Union Drilling's conference call today to review first quarter 2010 results.

Before I turn the call over to the management, I have some details to run through. You may have received an e-mail of the earnings release yesterday afternoon. If you didn't get your release or would like to be added to the e-mail distribution list, please call DRG&E at 713-529-6600.

A recorded replay of today's call will be available until May 12. 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, May 5th, 2010 and therefore you are advised that time-sensitive information may no longer be accurate at the time of any replay 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 caution to 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 on the call our Chris Strong, President and Chief Executive Officer; and Tina Castillo, Union Drilling’s Controller.

Now, I would like to turn the call to Chris.

Chris Strong

Thank you, Ben. Good morning, everyone, and thank you for joining us today. At this time yesterday’s press release our results for the first quarter of 2010 included revenues of $38.7 million, EBITDA of $3.7 million and a net loss of $6 million or $0.26 per share.

The bottom line result was disappointing when compared with the upward trend we saw in the fourth quarter of 2009. But I will remind you that the top quarter was not completely unexpected.

On last quarters call, I said the first is been sharpie. There expenses associated with putting idle rigs back to work and in the North East the unseasonably cold winter that is suffering storage in the balance also its going to drag on the operating results with rig shout down due to storms and delayed rig moves.

Also hampering our first quarter, unusual weather conditions in Texas and Arkoma reflecting record levels of snowfall. Well, I said the performance in the fourth quarter was most likely not sustainable due to the number of rigs going back to work that would incurred deferred maintenance costs. I had not anticipated that we would have as many rigs back on hire at this point or some of the incremental costs associated with fielding those additional rigs.

Utilization continue to increase in Q1 and so far that trend is continuing in Q2. Throughout the first quarter and especially in March, we mobilized a number of our Texas rigs away from the Fort Worth area to work primarily in the worlds buried [ph] oil play in West Texas.

With the relative strength of oil prices compared to natural gas, we undertook this strategy in an effort to diversify our revenue based and increased rig utilization. We’ve gone from it’s few as six rigs working in our Texas division during the fourth quarter of ‘09 to 14 currently.

Although pricing is very competitive, there’s a lot of work to be had which is a positive development compared to the fourth quarter when there was a very little drill [ph] activity.

While the increase in utilization is encouraging, we have absorbed substantial expenses associated with putting these rigs back to work. Many of these rigs have been sitting idle for the better part of the year, so we hired cruise prior to the rigs mobilizing into the field to addressed maintenance issues.

When things were slower and the rigs were down, we also borrowed equipment from some of these rigs over the last year in an effort to reduce expenditures on our working rigs, so they were costs associated with a replacing cannibalized components. Similar to other cycles in the past, we are seeing a lag of four to six weeks after rigs starts up before it begins to generate any significant margin.

I’ll talk about our outlook for Q2 and beyond in a few minutes but first I’ll ask Tina to go over the financials.

Tina Castillo

Thanks, Chris, and good morning, everyone. Revenue for the three months ended March 31st, 2010 totaled $38.7 million or $15,275 per revenue day compared to revenues of $54.3 million or $17,867 per day in the first quarter of 2009.

Additionally, our first quarter revenue, per revenue day declined approximately $1,500 when compares sequentially to the fourth quarter. The decline in average dayrates is primarily due to rigs growing off term contracts, the loss of the term rolling [ph] contracts that I’ve mentioned in the last earnings call and reactivated rigs going back to work at current market rate.

Operating costs for the first quarter totaled $29.6 million were $11,697 per revenue day compared to $34.8 million or $11,440 per day in the first quarter of 2009.

Sequentially comparing our OpEx per day in the first quarter to the OpEx per day in the fourth quarter we saw an increase of $1,235 per day.

As Chris mentioned, we’ve said on the last call that we expected average OpEx per day to increase as we completed deferred maintenance reactivating rigs and reverse some (inaudible) and that was indeed the case during the first quarter.

That trend is continuing during the early part of the second quarter but we expect the impact to moderate as the quarter progresses and fixed costs are spread over more operating day.

Drilling margin totaled $9.1 million or $3,578 per revenue day compared to $19.5 million or $6,427 per day for the first quarter of ‘09. Compared to last quarter, our margin per day was approximately $2,700 down, of which 400 per day is due to the loss (inaudible) contracts, 600 per day is attributable to startup costs on reactivating rigs, while the remainder of the decline is pricing in seasonality.

Going forward we expect average margins to remain compressed until the market tightens and we can gain some pricing leverage. In the mean time, we will continue to visualent [ph] over cost control.

General and administrative expenses decreased to $5.7 million compared to $7.7 million in the previous years first quarter due to our cost containment initiatives as well as minimal of bad debt expense this quarter compared to the prior year period.

First quarter EBITDA totaled $3.7 million in 2010, compared to $11.9 million in 2009. Depreciation and amortization for the quarter totaled $12.9 million up from $11.1 million last year reflecting the four new rigs that were activated in the second quarter of 2009.

We reported a net loss for the quarter $6 million or a loss of $0.26 per share, compared to a net loss of $271,000 or $0.01 per share in the prior year period.

On the balance sheet, we had $13.3 million drawn on our revolver as of March 31st, compared to $9 million at December 31st.

The increase is primarily due to a new 1000 horsepower (inaudible) here is mechanical rig that we acquired in late March that after some slight modifications will be deployed in Texas.

Cash used for capital expenditures during the first quarter totaled nearly $13 million of which $5.1 million relates to new rig we purchased, that I just mentioned, while the remaining 8 million relates to rig upgrades, such as Thornton and (inaudible) other maintenance CapEx.

We are pleased that the majority of the CapEx spent this quarter was funded through operating cash flow. Today our revolver balance is approximately 15.8 million or a 2.5 million increase over our March 31st balance, which is attributable to the completion of our pad drilling packages for five of our rigs.

Last quarter, we stated that our CapEx budget for 2010 was 26.2 million, with the recent rig acquisition, as well as an expected enhancements for iron (inaudible) mix, we now anticipate total capital expenditures for 2010 to be close to 36 million, absent any new opportunities to acquire new rig.

Looking at term contracts, which we define as contracts spanning at least six months or six wells, since our last earnings call on March 5th, we have four contracts expired, leaving us with 14 rigs generating revenues and margins under term contracts today.

Of the expired contracts, three of those rigs are still working well to well. Another contract was temporarily suspended for (inaudible) that one impact the number of days remaining on the contract once work resumes.

For the rest of the year, assuming no new term contracts, we have one term contract expiring in Q3 and four in Q4, which would leave us with nine term contracts, heading into 2011.

I’ll now turn the call back over to Chris.

Chris Strong

Thank you, Tina. I’m going to take a few minutes to talk about our outlook before opening up the call to questions, spend a good portion of my opening remarks, discussing how the relatively short-term issue startup costs drove down our margins and negatively impacted results, and that’s largely true.

However, I don’t want to give the impression that our margins are heading back up to 6000 per day in the immediate future. Even if start-up costs dissipate margins remain under pressure from both the top and the bottom.

Almost all of the rigs in our fleet that have been idle over the last year are going back to work at day rates that are lower than last quarter average, and have lower margins. So each one of them we put back to work reduces our weighted average day rate. On the bottom, we are experiencing upward cost pressures in the form of wage increases.

As domestic rig utilization increases, labor starting to become scares in some [ph] areas, particularly Appalachian. And it’s important that we pay competitive wages to retain our skilled employees. In general, we’ve been able to pass some, but not all of these additional expenses on to our customers.

We’re also running some rigs with extra employees in order to hold down the key personnel in an anticipation of higher rig utilization. Unfortunately, we are not seeing much of the seasonal recovery in Appalachian, where we have the bulk of our single engine rigs rated at less then 750 horsepower.

These rigs usually experienced an increase in utilization, as the snow melts in that part of the country drives out. But current natural gas prices appeared to be hampering that recovery. Well, the deeper Marcellus is a good market with decent day rates, there appeared to be enough rigs in the market to meet customer demand at the current time and therefore the pent-up demand that creates the environment for higher prices and term contract commitments remained elusive.

I stated on the last call that I expected to become more aggressive and increase our 2010 CapEx budget to deploy additional rigs into this market. This remains one of our primary goals, but until day rate show some positive momentum, it’s hard to justify the construction of new rigs at this time. We still have some equipment that make sense to move up to Pennsylvania and we will continue to be on the lookout for opportunities to acquired disserted assets that would be appropriate for our markets and can be put at work at rates to provide a decent return on capital.

The Arkoma market is performing reasonably well with an uptake in the utilizations toward the end of the first quarter. We are moving one rig out of that division up to a Appalachian after its contract ended in April.

With some minor modifications, that rig will be very well suited for horizontal Marcellus drilling. We’re also moving one rig out of our Arkoma and back to Texas. Our Texas market, which had been under pressure for most of 2009 is shaping us to be our strongest division in terms of utilization for 2010. Thanks to our shifts toward oil drilling.

We expect to have 15 rigs working during most of the second quarter, of which only three or four will be drilling in the Barnett Shale, while 11 or 12 will be drilling for oil in West Texas. Our shifts in Texas towards more oil exposure is in -- an important part of our diversifications strategy, but it does not mean that we’ve turn our back on natural gas. We remained committed to our strategy of operating some of the lowest cost of natural gas place in the U.S.

Overall, we are expecting the second quarter to look moderately bettered than the first, but there will still be a fair amount noise related to start up cost in April. Margins will continue to remain under pressure, until we’re able to obtain pricing leverage. The difficult thing to access about the market we’re in is that the horizontal rig count as high enough utilization for pricing power to be either at or closed at hand, but gas prices at a recent weakly objections are such, the rig count could role over before any meaningful margin improvement and it obtained.

As a result and until there’s more clarity, we will continue to see value and keeping our balance sheet clean and avoiding speculative new building. And with that Jamie [ph], we’re ready to take questions.

Question-and-Answer Session

Operator

Thank you, Sir. We will now begin the question-and-answer session. (Operator Instructions) One moment please. And our first question comes from Steve Ferazani with Sidoti & Company. Please go ahead.

Steve Ferazani – Sidoti & Company

Good morning, Chris. I do want to ask a little bit about the cost in Q1. Some of the rigs you returning to work, any concern that may be given that you weren’t -- they weren’t be profitable for the first. I think you said five, six weeks no one will be probably going into a slowdown with lower natural gas prices into the summer. Was there any hesitancy about putting some of these rigs back to work, you end up having them -- lay him down in the month or two?

Chris Strong

Steve most of the rigs, the incremental rigs we have put to work have really been for the oil side of things, the gas part of the business is pretty much remained the same. So again the lot of the costs have been associated with mobilizing rigs out of the Barnett Shale towards West Taxes.

I think we have a better in West Taxes in having those rigs running, given the oil versus gas disparity and pricing. I do think though that something we have to keep in eye on is the pricing is very competitive out in North Taxes. We have some of these rigs that have run and kind of gotten through that month or six weeks of not much margin, while some of the deferred maintenance issues are being addressed and putting a drag on the daily operating expense. Some of those rigs have turn the coroner and are starting to split out [ph] pretty decent margins even in a lower price environment.

We have a couple of rigs that we are having to addressed with customers where you know they’ve run for that period of time, and we either need to go back from our rig, or we need to do something else with the rig, because it doesn’t appear to be turning the quadrant.

At this point, we’ve got to that look like that, but most of the other once we’ve put to work are doing a little better and then -- the once we’ve put to work more in the March, April timeframe in the West Texas those who once [ph] who have to be monitored and close for to see them during the quarter so to speak and generate more positive margins.

Steve Ferazani – Sidoti & Company

Okay. What was the reason for the big sequential jump in depreciation?

Chris Strong

The additional rigs we’ve put on last year that is added to depreciation.

Tina Castillo

They had met the sequential objective.

Steve Ferazani – Sidoti & Company

Yes.

Tina Castillo

And what that was is we accelerate the (inaudible) on two rigs we decommissioned. And so that was a little over $900,000. Those two rigs we decommissioned were shallow rigs. And we took the opportunity during the quarter to decommissioned those. And they have an average three year life remaining, because we are now marketing [ph] them, we reduced (inaudible) to zero and basically where is the marked depreciation?

Steve Ferazani – Sidoti & Company

Are there any other rigs you might be concerning, doing that with.

Chris Strong

At this point we do our quarterly impairment testing and we have also been, as we’ve acquired rigs overtime that our higher horsepower, we have looked at some rigs to decommissioned. But that again we’ve had a rig in this past quarter that we decommissioned, that we re-commissioned where as it found work and we thought we just go ahead and take our hit for it. It's a bit of a -- it's all about estimates of future cash flows and you do the best you can. You talk to your operating guys, and then in this case we have one of our operating guys that happened to be in Texas saying well. We decommissioned that rig and now we’re re-commissioning it. So, now we have a fully depreciated rig that is back on.

But the smaller rigs in our fleet, I think I’ve mentioned on the last call, we've got, I guess, it's 28 of them now if we, we were at 29, but we have 28 rigs that are the single engine rigs that are sub 750 horsepower. Most of those are up in Appalachian, and in the aggregate they are on our books for a total of just over $20 million, that’s what $600,000, $700,000 of rig. There is not a lot of impairment or write-down exposure but if we do the analysis and go over with the division managers every quarter as we need to, to run our impairment analysis.

Tina Castillo

And that’s hard to say there is two rigs that we decommissioned and change the use (inaudible), it’s not an impairment. (inaudible) to kind of funny. You don’t get to book fixed assets at fair value; you book them at amortized cost. And so, those rigs still have value. We just don’t get to book them to that. We have to accelerate the depreciation and that’s why it’s not impairment, it really is depreciation. There is some value associated with those rigs. We can use those parts for other rigs or even the Netherlands [ph] that itself has some value.

Unidentified Analyst

Thanks. And the last one from me is just, you still have significant room on the revolver, Chris, what do you think best use of the capital moving forward might be?

Chris Strong

Yes. I am waiting, I am still hopeful that given everything that’s been announced in all the -- because of billion dollar plus deals that we continue to see flowing with these various partnerships up in Pennsylvania, we still believe the Marcellus is the market that is going to pick up substantially in rig count.

At the moment, we have some rigs that were idle because of weather that, that were Marcellus rigs that are probably not going to back to work until June based on location building and things like that. That’s not the kind of market where you really build new rigs of spec if you have equipment but it’s not tight enough to actually be able to get customers to pay standby; you know they are not sufficiently fearful of the inability to get equipment that they would pay you standby to get the June 1.

So, I’d like to see that market tighten but some of the other critical pep [ph] items where there is (inaudible), whether it’s pipeline take away other infrastructure issues that maybe keeping the rig count in an ample supplied area whether it’s 65, 70 rigs, you know there is certainly lot of research out there that suggest they can go well north of a 100 fairly quickly, but until we see some of that momentum which would lead to pricing power, as I said it’s difficult to comment the spec of the new builds. The kind of designs that are out there are probably in the $15 million to $17 million range, the kind of like that one of the rigs we’ve build a couple of years ago for the market was right around that same price range, but that was a rig that we got to mid 20s dayrate on in a three years term contract.

Right now, I think you’re seeing pretty nice electric rigs fetching maybe 16 in that market. So, that’s not really going to provide a very good return on capital. And you really need to see some momentum as I said in the dayrates up there before I think it’s wise to use the revolver and be more aggressive.

Unidentified Analyst

Yeah. Thanks a lot, Chris.

Chris Strong

You welcome, Steve.

Operator

Thank you. And our next question comes from the line of Max Barrett with Tudor Pickering & Co. Please go ahead.

Max Barrett – Tudor Pickering & Co.

Thanks, good morning.

Chris Strong

Good morning, Max.

Max Barrett – Tudor Pickering & Co.

First, as real quick. How many rigs did you have running during the month of April?

Chris Strong

During the month of April, I think we’re right at 135 this morning. Our average for April was more like a little over 31.

Max Barrett – Tudor Pickering & Co.

Okay. And then, Chris I understand, you know, there are a lot of moving pieces but as you look at your dayrates, you’re getting in a spot market, sort of combine with the ongoing role after the higher price term. Do you have any senses as to when we might see a trough in that, that point in average dayrate?

Chris Strong

Well, I would hope there is some trough here. I mean, we put out a lot of rigs very quickly with a lot of OpEx that I am hoping is not repetitive. It seems there is kind of jump in daily OpEx that we’ve had in quarter-to-quarter is not normal and it is not what I would consider recurring. But, when you’re moving a lot of equipment that you stole things off to keep other rigs running, this is part of the startup sequence and it go from six to 15 rigs in Texas. This is part of the costs and a lot of it’s swung into the P&L.

You know I said, I think some of this is going to bleed over in April. We didn’t catch it all at March, but we certainly did spend money in the first quarter to reactivate a quite a few rigs that hasn’t been running for the better part of the year.

Max Barrett – Tudor Pickering & Co.

Okay, and then last one from me, of the rigs you have working today, it looks like a good portion of those are working for private operators. Can you give us a sense as to why you’re hearing from the private guys as far as (inaudible) increase activity in kind how is that compare to you to some of your larger public customers?

Chris Strong

Well, yes, I think there is certainly the economy [ph]. The oil guys all seemed to be talking about more Pennsylvania sales, so there is certainly talk about additional rigs. But it seems like while there is discussion of a ramp-up of the rigs count in Pennsylvania there are other critical path items as I’ve mentioned that need to be addressed to get the rig count on to the critical path and to have pricing power.

Yes, I keep hearing people saying out, we’re going to go from four to 10 rigs but then I talk to our operating guys and then they say they barely have the people to be able to run the four rigs they’re running now. And they need to get more talent up there to run a larger program as an operator trying to double the rig count.

So there are those constraints to grow, it will be solved but sometime said --having been in this business for quite a while. You hear people say they are going to ramp (inaudible) and it’s going to get to a certain number and it’s going to be there by a certain point. And then, inevitably it seems like it always takes longer to get to that point and they said. So it’s difficult as the contractor to commit the capital base some of people say on conference calls. We are the guys who actually have to use the balance sheet to do it, so, yes, I was seeing this with some of the program starting up the spring where things are dragging a bit even though everybody says the Marcellus is a great play, there is a tons of money being invested were not getting the ramp up in rig count that you would expect there given all it's been setting all the money that changing hands. I think its coming, but it may take I don’t know whether it's -- this quarter, next quarter, the fourth quarter.

Unidentified Analyst

Great. Thank you very much.

Operator

Thank you. And our next question comes from the line of Andrea Sharkey Gabelli & Company. Please go ahead.

Andrea Sharkey – Gabelli & Company

Hi. Good morning Chris and Tina. How are you?

Chris Strong

Good morning, Andrea. We are fine. Thank you

Andrea Sharkey – Gabelli & Company

So I wanted to ask about if you could maybe think about your fleet and sort of put it out as, you know, the rigs that are capable of drilling in shale versus the ones that are in. What would your utilization look like for both of those pieces over the past quarter and then maybe today if it's little bit different?

Chris Strong

Well, Andrea, it’s a very glaring picture. Unfortunately, where you have utilization -- we have mentioned we have these 28 single engine rigs in the fleet which are the smaller sub 750 horsepower rigs. Utilization in that area of our business and yes, this is across different market even though many after in Pennsylvania. This is a utilization that is in the team basically, and then you have at the upper end the larger greater than 1000 horsepower rigs.

You’re looking at utilization that's more like 70% and probably going to go higher in the middle -- the twin engine rigs that are 750 to 1,000 horsepower, probably 50% to 60% utilization in that segment. But it's certainly from a capital standpoint most of the capital in this company is in the larger rigs, that’s where we've invested the money. As I mentioned earlier, if you have these 28 rigs that are sub 750 horsepower, that’s 20 million of our PP&E but that’s the area without any significant utilization.

In the past it has been very good return on capital business in 2008. 2008 and 2009, we lost about 60 million of revenue, half of those small rigs and about 20 million of margin. At this point, we haven't seen that gas prices at a point where a lot of these shallow drillers have the appetite to put those rigs back to work.

The larger companies they are -- maybe there they have other reasons to drill them, simply price, if its lease explorations, if they are trying to look for more acreage or delineate their acreage, move up their acreage [Audio Gap] they have spent lots of money on. Maybe some of them are little better hedged or lot better hedged than the smaller mom-and-pop independents [Audio Gap]

There is real stratification not only in the overall rig count but in the Union Drilling rig count between the vertical rigs up in Pennsylvania traditional [inaudible] shale Clinton and Medina, coalbed methane, lot of that business, just as impaired at the moment.

Andrea Sharkey – Gabelli & Company

Great. That’s helpful. And then maybe sort of following along that same line of thinking, if you were higher upper end rigs are at 70% utilization. How much availability you have for that to go to 90 to 95%? And do you think that when that could happen is that something that you think you could see in the next couple of quarter, or is that further out and what needs to seems happen to get that utilization?

Chris Strong

Well, some of that we’re adjusting, I mentioned in my comments we are moving some rigs around. We got a rigs that come off in contract, in Alabama, actually that’s heading up to the Marcellus. We got a rig in the Arkoma that is heading up to West Taxes. And we also have several rigs at this point that were previously doing horizontal work in the Marcellus that we will probably go out in the summer, but our employees right now, I mentioned the rig we are expecting to put out the first of June, but we don’t have enough tightness in that market to command that we spend by rate. If you don’t see the customers lined up looking for more rigs out there at this point.

Andrea Sharkey – Gabelli & Company

Okay. And then thinking about when those rigs do go back to work. Do you think that they are going to get or do you have plan for them to get on maybe about average margins dayrate in margins above this, yeah, sort of 3500 range are now that could help maybe not net holder to average dayrate but maybe offset some of the lowest offset it's going?

Chris Strong

Well, as I said I do believe that we incurred a lot of costs to the P&L and some of that would dragged into the second quarter with paying deferred maintenance where we -- you know, basically we’re managing for cash through a lot of 2009 and we learned about by drill pipe or repair engines or things like that if we had other engines associated with other rigs in the yard. And now, we’re having to pay some of that, yes, both on the capital and on the operating expense side to address the deferred maintenance on those rigs.

So, I think there is opportunity for the expense side to come down, some even in spite of some of the wage increases we’ve talked about. On the top line, the Marcellus is still a lot, even though I says it’s a little lose, it’s still significantly better in terms of pricing in the place like West Texas with the oil place. We were putting a lot of rigs out there, but it’s very competitive, and dayrates and margins are lower there, than they are up in Pennsylvania business.

The types of rigs where we put and detect into West Texas are not really suitable to run up in Pennsylvania. So, we don’t really have the option to simply move them up to Pennsylvania and obtain better rates that way.

Andrea Sharkey – Gabelli & Company

Sure. That make sense. And then just one last question for me. I had heard something on the -- I think it was the EQT conference call, that they were talking about some of the work they are giving in the Marcellus, testing using smaller vertical rigs that due under balance drilling could drill a vertical part because its factor. And you know, your rigs, your smaller sub 750 rig might be good for something like that. I was wondering if you would heard anything about that if you are working with them on testing that and there was any color you could provide there?

Chris Strong

That's a fairly common piece of workforce Andria [ph] we actually have a rig is doing that kind of work in the Arkoma Basin in on air a head of larger rigs that don’t have the under balanced stair drilling capability. You'll do the vertical section again higher penetration rates and also a lower day rate type rig to due to pilot holds sometimes they calls part of the rigs where not going down to kick up point manually even then another the larger rig with fluid will come in and do the horizontal influence.

We also have some of that going on in Pennsylvania right now not for equitable at the moment but most of our rigs in Pennsylvania as we had in our industrial presentations there shallow rigs as well as the larger rigs are equipped fair, drilling well. Most of the vertical drilling is traditionally been done in Appalachia has been done under wells so they are the again higher penetration rates is a hard rock up there and what you seeing in the Marcellus is either rigs being are equipped with those. And that will drilling there again with the kick up point and then convert the flow in to finish the horizontal section or a smaller better [ph] type rigs that will come in and do the air section in the larger rig will following. Equitable this is in a side is also had some success drilling horizontally on air but that's been some shallow, here on shale place down in Southern West Virginia.

Unidentified analyst

Okay, Great, Thanks that’s it for me.

Unidentified Company Representative

Your welcome. Andria.

Operator

Thank you, and our next question comes from the line of Victor Marchon with RBC Capital Markets. Please go ahead.

Victor Marchon – RBC Capital Markets

Thank you, Good morning, first question I have just a I missed the number Tina that you gave as related to the drivers to the operating cost increased sequentially in the first quarter the break down that she gave, do you have those number Sandy [ph]?

Tina Castio

We said that are margin per day was down approximately $2700 sequentially compared to last quarter. And about 400 of that was divisible loss of the tutoring [ph] contract. We've exchanged the tutoring contracts 30 year extension on –a rig in the [inaudible]. And 600 per day is attributable to standard cost where we activating rigs from the rest to the decline is pricing in seasonality.

Victor Marchon – RBC Capital Markets

Thanks and if I heard correctly it sounded as if the upper pressure on the cost will continue into this second quarter about moderate. So, the read through there that you could see the operating cost on a per day basis in creep up in the second quarter and then level out from there?

Unidentified Company Representative

It's possible you know I think we have some color on April in terms of utilization but we haven't got with both close rigs though we had. I thinks that’s really the months where we have a lot going on in March and we also had a lot in April towards utilization pick up and this whole move from 6 to 15 rigs in Texas and a lot of that is quite a materially are to be able to give you color on how much but I think its at this point its going to embed as I said early on the shifting comments that, we've taken a lot of rigs out and now its more or like, okay, we're moving one from the Arkoma down the West Texas were moving one rig after Marcellus. And those rigs are the one that's moving up to the Marcellus is already been working so there is not really the same differed maintenance issue that should have on some of these other rigs that have been lying around for year that should been taking parts also that you've taking parts off of

Victor Marchon – RBC Capital Markets

And is there a level from utilization standpoint that we should be looking at which you do start to see the rig spread out over the cost side, we’re actually seeing in operating cost on a per day basis to start meaningful decline?

Unidentified Company Representative

Well, I certainly hope to see that, some that in West Texas. As I said, you often have this month to six week where you don’t get any margin and you start to get concerned but then this higher than average cost loading as the rig has started up shaking up the crews, working with the new company and things that they may want that have to be acquired for the rig and then it settles down.

So I anticipate we’ll get to see some of that even though with specific reference are firming, the pricing is more competitive out there. But there is a lot of work out there. And I would say, right now in the Barnett, it may be middle of the play as far as F&D cost go. But the activity level in the Barnett with $4 gas is more associated at this point with our term contracts been a lot of new bid activity and there is a lot of activity in West Texas right now.

Victor Marchon – RBC Capital Markets

Does it relates to the Marcellus, the conventional activity. Chris what's your sense has into natural gas price, is operators we need to see on the strip of four, they start some putting some rigs back to work on the conventional side?

Chris Strong

The shallow -- I need to spend some time with some of our long-term customers up there. We are doing a little bit of it with some of our long-term customers that do these private placement memorandums every year and the pieces that I need to better understanding by guess is -- what are the issues that they are concerning besides the gas price, lot of this is worked in that's already in shale that's historically working very low gas prices. It's a very low F&D cost type play, the drilling is not very an expenses. The pipe, there're lot of low pressure pipelines is up there and you can put the gas into that. Is that their traditional business model where they had access to bank credit fairly easily on in unreasonable terms is that there? What about the tax side where they were raising money from mediums of high networks individuals who kick in 50 or 100,000 [inaudible] they raise $5 million to go to a summer drilling program? Are the tax benefits the same for those folks or has our oil and gas partnerships not as attractive from the tax standpoint to the investors who historically put money in this oil and gas partnerships?

Unidentified Company Representative

I think, I have some of the pieces and I am suggesting those because I think some of those with the other issues aside from price that is causing a slow down on the traditional conventional revolving in the shale or couldn’t [inaudible] or called that methane. I am somewhat surprised, I would say Coalbed Methane business is not very active that's been in the area up in the North East where degasifying coal that had a long, long mining operations. The horizontal Coalbed Methane drilling that we have several rigs set up for is not really there this year that’s something where it’s kind of adopt tales [ph] into what the coal companies are doing and how aggressive they need to be at opening up mines and degasification is vertical wells often took three years to degasify when we start doing a lot of force out of CBM you got that done to about 18 months. But that business is really not there right now and some of the specialty work we’ve done up there in the past for the coal companies specialty plugging and abandonment mid-work [ph], pulling out old casing and things like that ahead of long well mining operations is not as busy for us either. So, the coal companies don’t seemed to be as aggressive in the northeast as they have been in the past.

Unidentified Analyst

Sure. Well, thank you for that. And just on the dayrates side, could you guys provide any color as it relates to the margin differential between the rigs that will role off long-term contract this year relative to the first quarter average?

Unidentified Company Speaker

I don’t have it rig-by-rig, but if you’re -- and I think, even though, it may be a (inaudible) in way of looking at it. I’d say that the Marcellus is a fairly decent market. As I said, there may be 15, 16 a lot of West Texas is you know, some of that at $10,000. So, you could be seeing 5,000 a day of margin compression. We’ve probably seen more than that on some of the very high priced rigs that have rolled off, where you have rigs in the 20s that we mentioned are now on well-to-well. Those rigs could have gone, you know, rolled after 22 and then be down at 15.

Unidentified analyst

All right. So around five is plus is ballpark, okay. And the last one if I may, it just on the acquisition that you guys made. Can you just provide little color on that, I think I may have missed the price, but where is the rig you are going to be target at? Is there any contract behind it? What kind of horsepower, just a general any comment you can make on that one?

Chris Strong

Sure. It was the rig that was in East Texas that has been built by ENP Company two year ago, very well built with a good budget behind it, probably spend north of 10 million on it. 2,000 horsepower rig was [inaudible] large pumps, two drillers, but they had drilled two wells, and then I guess it's that one [ph] that we are doing in the drilling business there, plenty of other places to get rigs.

But unlike a lot of the rigs we looked at, it really was build two year ago, it was not build two years ago out of 30 year old parts. We brought it on its back. Essentially, we paid just over 5 million for it. I think we got a very good deal at $5 million compared to say the $17 million new build for the Marcellus, the UK and put it out in a much lower dayrate and get a return on capital.

So it's in our yard in Western [ph] Texas right now, just out side of Fort Worth. It may very well be going to West Texas to the oil drilling, but it's very clean straight rig that we thinks we bought right. We are looking at -- we continue to look at other rigs and profitability is been a lot of what we’ve see is not attractive.

Victor Marchon - RBC Capital Markets

Okay. Thank you for that, that's all I had

Unidentified Company Representative

Thank you Victor.

Operator

Thank you. Ladies and gentlemen if there are any additional questions please press star followed by the one at this time. One moment please. At this time I would like to turn it back to Mr Chris Strong for any closing remarks

Chris Strong

Well, thank you all for your interest in the Union Drilling and we look forward to talking to you after the next quarter in summer. Good bye.

Operator

Ladies and gentlemen this concludes the Union Drilling's first quarter 2010 earnings conference call. You may now disconnect. Thank you using AT&T teleconferencing.

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Source: Union Drilling, Inc. Q1 2010 Earnings Call Transcript
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