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Union Drilling, Inc. (NASDAQ:UDRL)

Q4 2007 Earnings Call Transcript

March 6, 2008 9:30 am ET

Executives

Carol Coale – Managing Director DRG&E

Chris Strong – President, CEO

A.J. Verdecchia – CFO

Analysts

Victor Marchon – RBC Capital Markets

Kevin Pollard – J.P. Morgan

Robin Shoemaker – Bear Stearns

Steve Farazani – Sidoti & Co.

Byron Pope – Tudor Pickering

David Cotter – [Iteral] and Company

Jud Bailey – Jefferies & Co.

Operator

Good morning ladies and gentlemen, thank you for standing by, welcome to the Union Drilling, Inc. fourth quarter 2007 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. If you have a question please press the star followed by the one on your touchtone phone. If you would like to withdraw your question, press the star followed by the two. I do ask if you’re on a speakerphone that you please lift the handset before making your selection. This conference call is being recorded today, Thursday March 6th of 2008. I would now like to turn the conference over to Carol Coale, Managing Director of DRG&E, please go ahead.

Carol Coale

Thank you Mary and good morning everyone, we appreciate you joining us for the Union Drilling conference call today to review fourth quarter 2007 results. Before I turn the call over to management I have some housekeeping details to run through. You may have received an email of the earnings release yesterday afternoon. If you did not receive your release or would like to be added to the email distribution list, please call our offices at DRG&E, at 713-529-6600. A recorded replay of today’s call will be available until March 13th. The information for accessing the telephonic replay is in yesterday’s press release. A replay will also be available via webcast by going to the company’s website at www.uniondrilling.com. Please note that the information reported on this call to be only as of today March 6th, 2008 and therefore you are advised that time sensitive information may not longer be accurate at the time of any replay listening.

Also, statements made in this conference call that are not historical facts, including statements accompanied by words such as will, believe, anticipate, expect, estimate or other 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 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 today’s company’s filings with the Securities and Exchange Commission, including Union Drilling’s annual report on form 10K for the year ended December 31st 2006 or for the year ended December 31st 2007 which the company expects to file before the end of the week.

Union Drilling cautions you not to place undue reliance on forward looking statements contained in this call. Union Drilling also does not undertake any obligation to publicly advice or revise any forward looking statements to reflect future events, information or circumstances that arrive after the date of this call. For further information, please refer to the company’s filings with the SEC. With me this morning are Chris Strong, the company’s President and Chief Executive Officer and A.J. Verdecchia, Chief Financial Officer. Thanks and now I’d like to turn the call over to Chris.

Chris Strong

Thank you Carol, good morning everyone and thank you for joining us this morning. If you saw yesterday’s press release you know this was a tough quarter for us. We reported revenues of $67.4 million and EBITDA of $18 million for the three months ended December 31st, 2007. Utilization was down across much of our fleet and we saw pricing pressure in certain areas. I’m going to go into more detail in a few minutes but first I’m going to let A.J. run through the financials.

A.J. Verdecchia

Thanks Chris. Revenues for the fourth quarter of 2007 totaled $67.4 million compared to revenues of $72.1 million in the fourth quarter of 2006. On the expense side, operating costs were up year over year primarily due to the addition of several ideal rigs in late 2006 and Q1 07. We also had higher repairs and maintenance expense as some work was completed on idle rigs and the included bonuses for field employees in operating expenses. In 2006, all bonuses flowed through general and administrative expenses which explains the $1 million decrease in G&A.

We also had increases in property taxes and insurance which were offset by lower costs for Sox consulting and relocation. Keep in mind that the fourth quarter of 2006 expenses also included a $1 million charge for the write down of intangible assets associated with the Thornton Drilling trade name. Income taxes increased to 46.2% from 40.3% of income in the fourth quarter of 06. Although revenue and pretax income declined significantly in the fourth quarter of 07, the meals per diem expenses did not decline, therefore the amount of disallowed meals as a percentage of pretax income was much higher during Q4 07, causing an increase in the Q4 07 effective tax rate compared to prior quarters. Net income for the fourth quarter totaled $3.8 million or $0.18 per share compared to $8.6 million or $0.40 per share a year ago on a GAAP basis. Excluding the trade name charge, last year’s EPS was $0.45.

Fourth quarter EBITDA totaled $18 million in 2007 compared to $23.5 million in 2006. Please refer to yesterday’s press release for a reconciliation of EBITDA to net income. As for our fleet-wide operations, revenue days totaled 4,021, down 13% from 4,597 days in the fourth quarter of 06. Marketed rig utilization for the fourth quarter of 07 was 61.6% compared with 74.5% a year ago. The average day rate in the fourth quarter was 16,753, up 7% from the year ago average of 15,677. Although this is the highest quarterly average day rate we’ve ever had, it’s only due to the fact that we had low utilization for our small lower day rate rigs rather than actual rate increases. Our drilling margins per revenue day averaged 5,833 for the fourth quarter of 07, down 11% from the fourth quarter 2006 average of 6,579.

We obviously generated significantly less cash flow in the fourth quarter than we expected and therefore we’re not able to completely payoff the remaining balance on the revolving credit facility. That balance stood at $9.6 million as of December 31st. As of yesterday, that number was $8 million. We recently paid a $4.5 million deposit on a new IDM Quicksilver rig and decided to utilized the revolver to pay annual premiums for corporate insurance this year, totaling about $2.5 million. Maintenance capital expenditures for the quarter totaled $8.5 million. Now I’m going to turn the call back to Chris.

Chris Strong

Thank you A.J. I’m going to take a few minutes now to break down what happened in each of our markets to impact fourth quarter results and what the outlook is moving forward. Among other things, I will differentiate between our larger rigs of which we have 34 and our smaller rigs of which we have 37. For these purposes, we’re defining larger rigs as those with multiple engines powering the rig’s jaw works and 700 horsepower or better. I’ll start with Appalachia. Last year was dryer and warmer than average and when cold temperatures finally did arrive in mid January, they generally remained below freezing until the beginning of March which provided for firm locations and access roads. This year has been wetter than average with February precipitation over double the historical average.

And while the average temperature has been lower than last year, it has fluctuated with warm spells being followed by cold, so the earth is not frozen solid. Excess of precipitation combined with constant freezing and thawing leads to muddy inefficient drilling conditions in this area. In Appalachia, we have 6 large rigs and 17 smaller rigs doing day work, plus 9 rigs on footage contracts. Utilization and margins for our large rigs was solid. In general our larger twin engine rigs stay on location longer and move less frequently. They have term contracts with bigger companies and smoother cash flow due to less sensitivity to weather and short term gas prices. Utilization for our small rigs was significantly down both sequentially and year over year.

These rigs tend to be on short term contracts. When costs escalate due to more difficult drilling conditions or when gas prices moderate, customers respond by reducing rig usage and our margins slip. For the footage rigs, utilization was decent but margins were significantly compressed. This is primarily the result of less efficient drilling due to poor weather conditions. This means it takes us more time to drill the same well which leads to margin compression on footage contracts. I should mention that these footage rigs are all booked for 2008 so margins should return to normal once the winter weather eases. Given what we’ve seen during January and February, I do not anticipate significant revenue improvement in this market in the first quarter.

However there may be some reduced costs as maintenance is often performed on rigs when they’re shut down and before the rig crews are furloughed. Therefore, there should be fewer rigs with negative margins being supported by the remaining operating rigs in the first quarter. Over the medium to long term, we are well positioned to capitalize on increased activity in the Marcellus Shale and other plays in this region. Given that we are drilling the Marcellus for sophisticated operators over a very wide area in Pennsylvania, I believe there will be additional opportunities to invest in equipment for this market that will provide excellent rates of return for our shareholders.

Moving over to the Arkoma Basin, utilization and margins were down across most of the fleet without a clear distinction between larger and smaller rigs. Day rates came down about 1,000 a day on several of our rigs during the quarter in order to remain competitive with market conditions. Until the market tightens and day rates rise, we will not see the absolute margin as high as it was in prior quarters in this market. Most of the Arkoma rigs are spoken for and have programs ahead of them. With the overall storage situation significantly better than either of the past two years and the one year strip close to $10.00, we should see activity in this part of our fleet pick up as we head into the second quarter. Longer term, I think we are well positioned in the Fayetteville Shale.

Until recently, the only substantial independent operators in the Fayetteville Shale play have been Chesapeake and Southwestern, both of whom have their own captive rig fleets. Over the last year, we’ve seen consolidation by other large independents and we’re maintaining a dialogue with these companies to ensure that we will be prepared to meet their needs as they ramp up activity heading into 2009. I believe there will be opportunities in the Fayetteville Shale to either acquire additional rigs or to move one or more rigs that we have in the Barnett Shale that are between 750-1,000 horsepower. Relatively speaking, Texas was our best performing division in the fourth quarter. The 5 rigs we run out of our Abilene Yard had a significant decline in margins despite relatively consistent utilization.

This was due to increased competition and lower day rates in the Eastern Permian Basin market. Our 6 ideal rigs in the Barnett Shale experienced some temporary margin compression. We had off higher days for the replacement of defective fuel lines that were covered under a warranty and we installed iron roughnecks on several of these rigs. These are automated pipe handling systems that increase safety and efficiency on the rig floor. As these rigs are on long term contracts, margins should return to normal going forward. The other 9 rigs we have running in the Barnett Shale experienced steady utilization and only a slight decline in margins. Even though contract terms and conditions are not as favorable as they were a year ago when rigs were in shorter supply, the North Texas market continues to look very solid. Overall, it’s been a tough quarter in Q1 is likely to be soft as well.

We’ve implemented cost cutting measures on a number of our rigs that are experiencing continued low utilization and we have approximately 42% of our estimated 2008 cash flow currently covered by term contracts. We continue to believe in our unconventional natural gas focus and think that we are well positioned to capitalize on long term opportunities in these markets. Mary, I think we’re ready for questions now.

Question-and-Answer Session

Operator

Thank you. And ladies and gentlemen we will now begin a question and answer session. As a reminder, if you have a question, please press the star followed by the one on your touchtone phone. If you would like to withdraw your question, press the star followed by the two. If you’re using speaker equipment, you will need to lift the handset before making your selection. Please ask one question and one follow up and re-queue for additional questions. One moment please for the first question. And our first question comes from Victor Marchon with RBC Capital Markets, please go ahead.

Victor Marchon – RBC Capital Markets

Good morning everyone. The first question I have is just on the Appalachia and the Appalachia region, you guys had, were undertaking a couple of conversions on your rigs there, I just wanted to see the status of that as well as some other opportunities you may have on conversions going forward.

Chris Strong

Victor, we have the new rig that we announced for $17 million that we’re building for Appalachia and we’re looking at some other opportunities to acquire rigs up there, but as far as refurbishment, we have a rig that is complete and ready to go. We decided not to put it into service even though it could have gone into service because it was going to go for a customer for whom we were already running a rig and given the weather conditions up there, we were basically going to run out of locations very rapidly by running two rigs simultaneously. So as far as rigs that are under construction in that market, we really don’t have anything up there and then again we have the new build rig that is being built by IDM down in Houston.

Victor Marchon – RBC Capital Markets

Okay, just switching to the operating cost, you know you guys averaged over $10,000 a day, close to $11,000 a day in the fourth quarter. How do we look at the operating cost per day on a go forward basis?

Chris Strong

I think some of that is higher in the fourth quarter, as I mentioned in my comments, I think there are costs when you have a lot of rigs going down, especially rigs that have run pretty steadily for a couple of years that as they come into the yard, the crews are terminated immediately. There are maintenance projects and those sorts of things. So we had quite a number of rigs as we looked through the individual rig detail that had little or no revenue days during the quarter but significant maintenance and repair expenses where we kept the crews on and spent on them.

So you had the remaining rigs that were operating and generating rate and margin, in effect subsidizing the rates that were down and having maintenance type work performed on them. I think there’ll be less of that in the first quarter even though the utilization isn’t going to be significantly better. One of the things, given our delayed reporting compared to some of our peers, we have a pretty good handle on where January and February have come out and there’s not a lot of top line improvement in those months. So what I would expect to see though is some improvement on the daily operating expense and then as more of the rigs are back working as we head into spring, you’ll see that number come down some more.

Victor Marchon – RBC Capital Markets

Okay, would it be fair to assume that you get back below $10,000 a day or are you probably going to stay somewhere between 10 and 10.5?

Chris Strong

I think it’s probably fair to say that we’d be below 10.

Victor Marchon – RBC Capital Markets

And that would be a progression as you work through, as you go through the year?

Chris Strong

Probably, I think you’ll probably see some of that happen as we head into the second quarter. You know typically the third quarter is our strongest quarter because of Appalachian seasonality. That’s the quarter when you have the most rigs running normally and higher percentage of rigs running generally leads to lower operating expenses. But I think we’re going to see a more significant drop as we head into the second quarter.

Victor Marchon – RBC Capital Markets

And the last one is just on price, just wondered if you could walk through what you’re seeing on a spot basis in you know your primary areas in Texas and Arkoma and Appalachia, just talk about what you’re seeing currently, is pricing stabilizing or are you still seeing a little bit of downward pressure? I’m just wondering if you could put that in context for us?

Chris Strong

Sure, the Appalachian market is pretty tight, we haven’t seen anything really in terms of downward pressure. There’s a lot of scrambling for crews up there. I think again when the weather breaks you’re probably going to have some pent up demand because budgets have been approved up there but the drilling activity is pretty low. I think you’re going to see, as I’ve said, a scramble for both rigs and people up there heading into the summer. And as I mentioned earlier on my comments, we’re pretty well booked up there for the year.

The Arkoma Basin has been soft, I guess some of this depends on where gas prices are but at the $9.00-$10.00 strip range, I can’t really see how that’s not going to get fairly active for us if those prices sustain. I mentioned also, we’ve had a few rigs where we’ve had to take some rate decline, maybe $1,000 a day in that market, especially on the larger rigs that had the higher dollar contracts in that market. In Texas, I mentioned we’ve seen some margin compression on the Eastern Permian Basin rigs. Haven’t really seen much more pressure there and I’m pleased to say that those rigs are all off the lot and working but we have had to make some rate concessions to continue to have them utilized.

Over in the Barnett side with the other 15 rigs we have down in North Texas, the larger ideal rigs are all under term contracts so they’re not going to be impacted and there’s been a little bit of softness for us with the sub 1,000 horsepower rigs that we have that in that group of those other 9 rigs, those are the ones that are a little tougher to place and I mentioned we may be moving one or more of those up into the Fayetteville Shale depending on what sort of contracts we’re able to attain up there. We’ve also been looking at some projects where we’ve put rigs together a couple of years ago and fabricated essentially a new rig around an older model draw works.

There are now some fabricators out in West Texas that are getting into the business of building draw works and we’re looking at putting some higher horsepower draw works on some of our existing rigs. And those are probably cap ex projects in the $1.2 million range to upgrade the say an 800 horsepower rig that has a big derrick and substructure on it to 1,000 or 1,200 horsepower. Those are probably some things we’ll look at doing over the summer as we see the Barnett Shale market gravitating more to 1,000-1,500 horsepower type rigs.

Operator

Thank you our next question comes from Kevin Pollard with J.P. Morgan, please go ahead.

Kevin Pollard – J.P. Morgan

Good morning Chris. I wanted to follow up on some of this utilization issues here, if I could start with Appalachia first, what, I guess with the weather kind of not working for you in Q4, at what point would you expect the, just following the normal seasonality up there for the utilization to kind of return to normal. It sounds like it’s not happening in Q1 and I know usually in the early spring you have a little bit of softness. So how long are we looking at it this point until you think that market returns to normal?

Chris Strong

I hate to say it Kevin, it’s one of those “it depends” type answers where you’ve got the weather issues. I mean we’re expecting some, what do they call it, wintery mix down here in Fort Worth today and we’ve had snow a couple days ago, then we had nearly 70 degrees yesterday and now we’re going back down to some more snow. Those are the kinds of, it’s the kind of weather pattern that we’ve had up in the Northeast and probably we had a better than average year last year, even though it wasn’t really great for storage withdraws but we had extremely mild weather and extremely low precipitation, we were on average for the fourth quarter and first quarter of the 06, 07 winter, we were about 25% below normal in terms of precipitation out there.

This year we’re about 25% over normal in terms of precipitation and unfortunately there hasn’t been any real pattern up there for long solid freezes. There’s just been 5 degree and 10 degree weather followed by 50 degree weather which when you combine that with a lot of rain makes for very difficult conditions and you know I alluded to it on my comments on the script of the conference call where you look at that in our footage rigs where basically it’s on us in that market. We can continue to work them but the inefficiency is our loss and not the customer’s loss as you would see on a day work contract and you know while the utilization on those rigs has held steady, the margins have gone down a couple $1,000 a day.

The penalty we’ve taken on the day work rigs in that market is basically the customers have said you know we’re throwing in the towel until we can build locations again. And it just really depends on how much longer winter persists. I mean it’s unfortunate, we get hit with more of this than some of our peers being up in Appalachia but I think in general, continued cold in the Northeast and these sort of conditions, if it persists through March, it’s going to lead to a pretty favorable storage number coming in the shoulder season.

Kevin Pollard – J.P. Morgan

Let me ask the question this way, Chris, you know with the spring thaw kind of just around the corner up there, is it a situation where we could be looking at really having to get into the true summer months, you know late May, June, July before you really see things return to normal up there?

Chris Strong

It’s possible, I guess I’d keep an eye on what’s going on up in the Northeast as far as weather conditions and that should give you a pretty good idea of how active people are going to be able to get in the second quarter. You know we have had years up there where it’s really been out in April before things settle down and you’re hitting the drilling hard.

Kevin Pollard – J.P. Morgan

Okay, if I could you know kind of switch gears just on a bigger utilization question, if I sort of listened to all your commentary from the various regions, as well as your comments on utilization being soft so far in Q1, really it sounds like the only thing that’s changed from Q4 is probably the ideal rigs are back to work. Is that fair?

Chris Strong

The ideal rigs were working continuously through the fourth quarter, it’s just we had some, we did have some warranty down time which you know probably cost us in terms of margin, I don’t know, $100,000-$200,000 on each rig, something like that, during the quarter, both to do the iron roughneck work and to do some of the warranty work. I would say as far as what’s stable, as I mentioned earlier, the larger rigs that we have up in Appalachia were very stable through the fourth quarter and I don’t anticipate any difference, rather in the first quarter for those rigs.

The 9 other rigs that we have running in the Barnett Shale were pretty stable. There may be a little bit of pressure on some of the smaller rigs in that fleet as I mentioned, we have a couple rigs that are in the 750-800 horsepower range and those 9 rigs that are more difficult to place than the 1,000 horsepower and higher rigs. Those are probably the areas of stability and I am not seeing, at least to this point the bounce back of the Arkoma fleet, even though you know again a lot of things are booked, there’s a lot of contract cover but these are not the two and three year payer take type drilling contracts, these are more, we have 15 wells to do and we want the rig but we’re not quite ready to go yet and there’s not enough overall demand in that market where you can say if you’re not ready to go we’re going to take the rig somewhere else.

Operator

Thank you our next question comes from Robin Shoemaker with Bear Stearns, please go ahead.

Robin Shoemaker – Bear Stearns

Yes, thanks. Hey Chris, wanted to ask about, go back to Appalachia for a minute and it seems like you know periodically there’s some hope or optimism that terms and conditions of contracts in Appalachia would get a little bit better, but it seems like that it’s still the case that all the risk of weather downtime and everything related to that is on the contractor rather than on the operator.

And you indicated that your capacity in Appalachia was pretty well booked for 08. But I guess it’s under the same terms and conditions that have kind of always prevailed there, can you give us some insight as to whether you think there’s any headway to be made and I say that because I guess you’re still really the market leader in that market and the periodic optimism on that market changing has kind of never really materialized if I could put it that way.

Chris Strong

I think that comment is fair Robin, except for the, again for the larger rigs, those are the half dozen or so rigs we have up there that are more highly sought after on term contracts. As the, I guess the bulk of our fleet though in that area is the smaller single engine type fleet, those are the rigs that drill 7-10 day type wells. These AFEs for those types of wells are such that you don’t get as good a location road, you don’t get as good a location itself. Not always smaller customers, I mean there’s some very large customers up there that drill a lot of shallow wells and even some of these new shallow horizontal Devonian wells up there.

The types of locations and the length of time that the rig is on location is very different from what we saw say in the Trenton Black River up in New York and what we’re seeing with the deeper Marcellus Shale projects where you’re going to be on location a lot longer, you’re going to have many other service companies that are going to have to come into that location with bigger equipment, whether it’s fracing equipment, directional drilling crews. So you tend to get a better location, a better location road and a longer time between moves and I think those are the things that lead to the better contract stability where you are getting the year long contracts with a guaranteed number of days of minimum utilization. But, so again on the smaller rigs in Appalachia, I don’t know that we’re in a position to be able to create the sort of pressure on terms and conditions that you’re talking about.

Robin Shoemaker – Bear Stearns

Well there has periodically been some hope that that might be the case, I guess it’s just the supply demand dynamics and the value added proposition just isn’t sufficiently strong to get it. And I guess that’s also where you get into the footage type of contract arrangement which also puts the risk on the contractor.

Chris Strong

Correct, the footage actually, we’ve been drilling footage up in, well it’s generally North of Pittsburg in the Clinton-Medina Sands for years and it’s also a choice on our part that we have a lot of crews that are very familiar with that area and there’s some difficult drilling conditions to get through some of the salt layers where other competitors have bloodied their noses over time. That is an area where we think we make very good returns on footage and have chosen really not to go to day work, although there is high seasonality, the overall return on the capital invested in that portion of our rig fleet remains very high.

Robin Shoemaker – Bear Stearns

Okay, just one other thing, you’ve had your eye on the rig market and I know that your balance sheet will certainly allow you if the right opportunity came around, are you still seeing the asking prices for assets at lofty levels reflecting the market where it was a year ago rather than today or are you starting to see anything that might be you know an opportunity for Union to acquire assets in some of your stronger markets?

Chris Strong

You know I think it’s breaking down between the onesies and twosies if you will where we can pluck off rigs, there are the small E&P type companies that have maybe bought a few rigs and now don’t want to own rigs. I think there’s some of those opportunities and then on the other side I agree with you that we have the balance sheet flexibility to probably do something a good bit chunkier and we’re looking at some of those opportunities and there are several out there. I can’t really go into much more detail but my view Robin is that I think there are continued opportunities to in essence stick to our knitting and look at additional rigs in our markets and possibly other markets but probably not going after directional drillers or service rigs or wire line companies or any of those other businesses to cross sell more services at the well head if you will.

Operator

Thank you our next question comes from Steve Ferazani with Sidoti & Co, please go ahead.

Steve Farazani – Sidoti & Co.

Good morning, looking at your operating expenses, it would appear that you probably didn’t reduce the size of the drilling crews at all. Given spotty utilization with some of the smaller horsepower rigs, have you looked at that at all, are there opportunities to potentially reduce employment?

Chris Strong

You know we’ve actually cut back and furloughed employees. As I mentioned, this is not terribly surprising to me that we had a number of these rigs that have been out in the field running pretty steadily for a couple years and there are things you can do while the rig is running but there are also maintenance type operations that flow through the P&L on the rigs that we have performed while the rigs were off hire and brought back into the yards.

Those are the times where you keep the crews on, you continue to run not only labor but other operating expenses through the P&L and then after those maintenance procedures are done, you lay them off. And a good bit of that has been done which is why I think you’ll probably see some softening in terms of the op ex per on hire day even though maybe the revenues aren’t going to grow substantially in Q1. So I think we have looked at that and you know obviously we’re looking at the general economy, although we think the gas sector looks good. You know we’re concerned about the possible fall off in demand for natural gas if we get into a real recessionary funk and we’ve had those discussions with our operating managers.

Steve Farazani – Sidoti & Co.

Any issues with, you’re certainly seeing some trends where maybe there’s going to be less demand for the shallow vertical wells in Appalachia, any of these rigs not going to fit within your fleet moving forward, what’s your take there?

Chris Strong

I certainly hope that’s the trend. I think even the single engine rigs that we have are the larger derrick hook load type rigs, we passed on a lot of deals up there. There are an awful lot of single engine rigs that run in that market that are, say have derrick capacities of 110 or 130,000 pounds. Most of what you’ll see in our fleet is 200-250,000 pound derricks on the small rigs.

A lot of the rigs that we have that are small are still large enough o equip with top drives for horizontal work. So if the Devonian Shale in particular goes much more to the horizontal, I think there are going to be a lot of small rigs in Appalachia that we don’t own that are going to be marginalized. That’s probably more of an opportunity than a threat for us given the profile of a lot of the other single engine rigs owned by the mom and pops up there.

Steve Farazani – Sidoti & Co.

So the long term trend there as that movement takes place is more adopt the directional drilling programs, you view that long term benefit?

Chris Strong

I think that’s why you’re seeing people, large independents paying high dollars to get into the market, they’re not going to pay those dollars to get into the market to just drill the same old vertical Devonian Shale well that produces 200,000 cubic feet a day, they’re going to want to drill it horizontally, they’re going to want to figure out the better frac and instead of having that 200,000 a day for the next 15 years, they’re going to want 2 million a day for the next 2 years.

Steve Farazani – Sidoti & Co.

Then just on back to that January contract you announced. How quiet has it been or ongoing discussions with perhaps that customer, other customers. What are your chances for these larger new build contracts moving forward?

Chris Strong

I think there’s definitely demand up in that area for more of the say 1,000 horsepower plus rigs that can be efficiently moved around up in the Northeast. We are working and doing drilling in the Marcellus Shale all the way from the Ohio border to the New Jersey border right now and we’re also up in Eastern New York State near Binghamton or actually North of Binghamton up towards the Catskills, so there are a lot of big named companies poking around all through Pennsylvania right now. I think the resource bases there and again like some of these other shale plays, it’s a question of developing the appropriate completion technologies to efficiently extract the resource that’s in place.

Operator

Thank you our next question comes from Byron Pope with Tudor Pickering, please go ahead.

Byron Pope – Tudor Pickering

Good morning, want to dig down a little deeper on the Arkoma and Chris if I math this right, I mean it sounds like you’ve got maybe 19-20 rigs in Arkoma and I wanted to see if you could give us a little more detail in terms of how many rigs do you have today working in the Fayetteville versus the Woodford versus the so called conventional Arkoma. And then also the mix of larger rigs versus smaller rigs, if you could provide that level of detail.

Chris Strong

I can provide that level of detail. I need to be cautious about not doing too much to get us into segment level reporting which is something we’d like to avoid. When we bought the Thornton Drilling fleet to have a platform in the Arkoma Basin, that fleet was primarily drilling and [hard showing] coal [scene] which is a, vertical as well as horizontal coal bed methane play. At this point, through investing in the circulating systems and other features of a lot of the rigs in the former Thornton fleet, we have two or maybe three rigs remaining out of that original 12 rig acquisition that are drilling in the coal still. The rest of those rigs are now drilling over on the gas side of that business.

Over in the Fayetteville Shale part of the business, we have a yard in Searcy Arkansas, we have five rigs assigned to the Searcy yard outside of Little Rock, actually, Northeast of Little Rock. And that area has kind of been up and down for us. We had a contract to run all five rigs with one customer and the mix of those rigs over there was one large rig and four single engine rigs that we had brought down from Colorado and Utah. As it turned out, based on drilling conditions over there, the customer wanted to move away from the smaller rigs and replace them with larger rigs and we accommodated them to some extent, but their geological results have not been as good as they’d hoped in the far Eastern part of the Fayetteville Shale play over towards the Mississippi River.

They’re doing a lot better in White County than say the more Eastern counties like Woodruff and Saint Francis Counties in Arkansas. We also did a rig purchase of a larger rig for another small customer over there and that has not panned out. I don’t know if that customer is bankrupt yet but they’re down at I don’t know, a $0.01 or so a share and that has not worked out terribly well. And what I expressed on the scripted comments were that it’s nice to see folks like XTO and Petro Hawk coming in and doing some consolidation and paying North of $10,000 an acre to get into that play.

XTO happens to be our company’s largest customer between the work we do for them in the Fayetteville and the work we do in the traditional Arkomas as well as the work we do here in the Barnett Shale. So we’re planning to speak to them in greater detail, the initial take I believe is that they’ve spent a lot of money on acreage and that they are getting things together to ramp up drilling activity later in 08 and into 09. As far as the mix of rigs, we’re going to put out a lot more detail into our 10K which we’ll file Friday. We’re putting in a table of [forced] hour per rig, rig market of each rig and air circulation systems for underbalanced drilling, yes or no, circulation systems for horizontal drilling, yes or no. So a lot of that will be available to you on Friday.

Byron Pope – Tudor Pickering

Okay, great, that’ll be very helpful, appreciate that. And Chris, kind of a bigger picture question for you and it just relates to your smaller rigs. I mean over time as far as we can tell their industry still has another 40, 50 new build rigs that are coming to market, probably going to go to work in new unconventional gas shale plays and you’ve moved, already moved 5 of your rigs from the Barnett to the Permian Basin, I guess the question is over the next 12-18 months, I mean competitively, what can you do to those smaller rigs, for those rigs to be competitive and to be able to find work if in fact these incremental rigs coming on the market will be going to a lot of the gas shale plays that you’re already in?

Chris Strong

Well I don’t think its accurate Byron to say that we’ve moved 5 of the rigs out of the Barnett into the Easter Permian. When we acquired the assets of Spa Drilling, they were headquartered in Abilene and 3 of the rigs we acquired from Spa were working in that shallow market. But we have moved a couple rigs over there out of the Barnett that are in that 750-1,000 horsepower range. As I mentioned earlier, we’re looking at increasing the draw works capabilities of a couple rigs this summer. We’re probably looking at three different situations there where we feel the derricks and substructures and circulation systems are more than adequate but that customers now are really gravitating to 1,000 horsepower or better on the hoisting systems for the Barnett, it just seems to be a psychological floor.

We haven’t had problems drilling Barnett Shale wells with 800 horsepower rigs but to your point there are more 1,000-1,500 horsepower rigs available in this market and given a choice, drilling engineers on the operator’s side would rather have more horsepower than less horsepower. So there are some upgrade projects we have on several of these rigs where we think the rest of the rig is fully capable and $1.2 type cap ex investment to put a bigger beefier draw works on the rig makes some sense.

Byron Pope – Tudor Pickering

Okay and then my last question, does actually relate to cap ex and your thoughts on 08 cap ex and I’m assuming that whatever number you tell me is going to be mostly maintenance cap ex and so again just curious about 08 cap ex thoughts at this point.

Chris Strong

I think our cap ex this year for maintenance is probably going to be a bit lower than last year. We were still like a lot of other people, more in the scramble mode a year ago where as we exited 06 and moved in 07, there was still a lot of concern about availability of tubulars, engines were on back order. The industry was really tooling up and there were real concerns about access to those sorts of supplies. And now things are more balanced and we probably have a bit more on the inventory or capital spare side right now than you might normally have as a result of concern about not having enough drill pipe in the past.

So some of that will probably smooth out this year and the maintenance cap ex will be a bit lower than last year. As far as the acquisition cap ex, we have this one announced rig, I wouldn’t be surprised if there are a couple other ones that show up that make sense to us on a one off basis and as I mentioned when Robin was on the line, you know we may have the chunkier deal, but that’s hard to really budget for. You know that’s just whether something makes sense and you get to the table and do one of those larger deals.

Byron Pope – Tudor Pickering

Okay so I guess I missed that maintenance cap ex number then so for 08?

Chris Strong

I’d probably say around $30 million.

Byron Pope – Tudor Pickering

Okay, great, thanks, I appreciate it.

Operator

Thank you. Ladies and gentlemen if there are any additional questions please press the star followed by the one at this time. As a reminder, if you’re on a speakerphone, please lift the handset before making your selection. And our next question comes from David Cotter with [Iteral] and Company, please go ahead.

David Cotter – [Iteral] and Company

Hi Chris, after last quarter there was a lot of speculation as far as capital allocation and that and right now it sounds like it’s looking more towards acquisition, rig acquisition, but there’s a lot of speculation about possible share repurchase and dividends. Any comments there?

Chris Strong

Well, last quarter you know I haven’t seen the screen in the last half hour but a lot of that discussion was in the fourth quarter when the stock was in the 12’s and I think some of the appetite to look at share repurchases dissipated when the stock rose. As far as dividends are concerned, we have at least to this point been able to find opportunities that have left us with a remaining balance on the revolver. I think the multi year term contract that we’ve secured up in Appalachia for the $17 million new build is a good direction for us to go in.

If we don’t service that market and that market is growing rapidly, we’re going to relinquish the advantage we have right now of being the only publicly traded driller in the Appalachian Basin market. So I think to the extent that customers are having conversations with us about equipment that needs to be built to service growing demand up there, either we step up and do those deals or they’ll find someone else to do those deals.

David Cotter – [Iteral] and Company

Then when should we expect to see some I guess verification of Appalachia as the next hot region?

Chris Strong

You know I think it, probably Range Resources is probably a company that is good to keep an eye on in this area. We have drilled a number of the horizontal Marcellus Shales wells for them in Western Pennsylvania. Those are the wells that at least right now they’re talking about the IP rates, whether it’s 3-4 million a day. I think those are the ones that are probably the best to follow closely and determine if in nine months from now or well they’ve been on for several months, so maybe you’ve got another six months or so to wait to see if in fact the production that’s coming out of those wells has held up and the kind of decline curves are going to be similar to or better than say the Barnett Shale and that you can realistically say that this is a 2 BCF well.

We have gone into other areas in the past and drilled where things were you know generating a lot of buzz so to speak and drilled and there were terrific IP rates and then a few months later there was no gas and you know all the sudden there were no drilling rigs in demand either because they did not sustain and the ultimate recoverable reserves from those wells were much smaller than originally thought. So that’s a long winded answer but I’d say if you probably six months out, we’ll have a lot better information.

And then in some of the other areas, be it the middle of the state where we’re going to be doing some drilling or even over in the Eastern part of the state where we’re doing much more, we’re doing some coring work over there. You know that’s a little more in its infancy to determine if work say in the Poconos that we’re doing is going to turn out as well because we haven’t even gotten to the point where we have producing wells over there.

David Cotter – [Iteral] and Company

Okay, great, thank you.

Chris Strong

You’re welcome.

Operator

Thank you, next question comes from Jud Bailey with Jefferies & Co, please go ahead.

Jud Bailey – Jefferies & Co.

Thanks, good morning Chris. Hey, question that I apologize if you covered this but the ideal rigs and the work you had done to those during the quarter, is there any way to quantify what kind of impact that did have on the fourth quarter?

Chris Strong

I think I mentioned at one point about 100-200 per rig was the decline versus Q3. You know those rigs are still, because they’re under term contract, will continue to be very high return rigs for us. You know they’re certainly meeting our expectations even though you know we bought them early on in National Oil Well’s run of these rigs and we’ve had you know some learning curve type issues that they’re probably working out on the successive ideal rigs that they build but I think we got the rigs at a very attractive purchase price and one of the costs is that were early on in that production run.

Jud Bailey – Jefferies & Co.

Okay, so if I kind of look at what impacted the quarter, it sounds like the ideal rigs will probably from a margin perspective probably move back up to probably where they were before. But some of the smaller rigs in Appalachia are still going to have some issues but the larger ones probably still be okay since they’re on term contracts and probably somewhat staying in the same place. Is that fair to say?

Chris Strong

Yes it is, but you know I don’t think that the small rigs that we have in Appalachia or for that matter the ones we have in the Arkoma are all the sudden going to be without work. I think that we’ve had some seasonality issues that were a lot worse this year than, well in either of the past two years for that matter and although it’s painful it’s probably setting up the general drilling market going into the rest of the year to be pretty good given that we’ll finally have a decent level of gas and storage heading into shoulder season.

Jud Bailey – Jefferies & Co.

Okay, that’s all I’ve got, thanks.

Operator

Thank you, there are no further questions, I’ll turn it back to management for closing comments.

Chris Strong

Thank you, thank you all for joining us today and I look forward to speaking with you again on our first quarter conference call.

Operator

Thank you, ladies and gentlemen that will conclude today’s teleconference, we do thank you again for your participation and at this time you may disconnect.

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Source: Union Drilling, Inc. Q4 2007 Earnings Call Transcript
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