Welcome to the Union Drilling’s third quarter 2009 Earnings Call. During today's presentation, all parties will be in a listen-only mode. Following the presentation, the conference will be opened for questions. (Operator Instructions)
I would now like to turn the conference over to Ben Burnham with DRG&E.
We appreciate you joining us for Union Drilling's conference call today to review third quarter 2009 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 November 10th. Information for accessing the telephonic replay is in yesterday's press release. The replay will also be available via webcast by going to the company's website at www.uniondrilling.com.
Please note that information reported on this call, speaks only as of today, November 3, 2009 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, I'd like to turn the call over to Chris Strong, President and Chief Executive Officer whose is also joined by [Tina Castio], Union Drilling’s Controller.
It is disappointing that our third quarter results were not unexpected. The North-American oilfield service market continues to be a difficult environment and during the third quarter, the average U.S. rig count was down by more than 50% from a year ago. As a result our third quarter revenues decreased 57% to $35.2 million.
We reported a net loss of $4 million or 17% per share for the quarter and EBITDA of $6.8 million, that’s a bad news. The good news is that from an operational standpoint things started to turnaround in the third quarter and this may have been the bottom in terms of utilization.
The U.S. rig count actually increased sequentially by 4% from the second quarter, which is the first increase we have seen in a year. Our average utilization for the fleet was 30.6% during the quarter, but it improved each month from 28.4% in July to 34.0% in September. This overall improvement came from all three of our operating areas with Appalachian showing the largest increase from July to September and Texas showing the smallest increase. We also continue to reduce our debt and came out of the quarter with less than 5% debt-to-cap and over $80 million of availability on our revolving line of credit.
Regarding our fleet, we did not add any new rigs or retire any old rigs during Q3, so we are still marketing 71 in total. However we’ve continued to invest in rig upgrades while the utilization is slow with several walking packages being added for pad drilling and top drives order to improve horizontal drilling capability.
Since price-to-replacement value and bank facility asset coverage receive attention at the bottom of the cycle, I’m going to touch briefly on fleet valuation. Our bank agreement requires that our rig fleet and related equipment be independently appraised at least annually to determine if there is sufficient collateral on a Forced Liquidation Value basis to back the size of this facility.
In 2008, the fair market value of the fleet was $438 million. In spite of $32 million of new rigs added in 2009, the fair market value of the fleet declined to $407 million, which means there was about 14% year-over-year decline in the existing assets.
Not surprisingly, the orderly liquidation or auction value of $301 million, and the Forced Liquidation or 'as is where is' value of $224 million declined by even larger percentages from a year ago. With a 75% advance rate against forced liquidation value of our assets, we continue to have plenty of asset coverage for our $97 million revolving credit facility.
With regard to our CFO search, we are in the middle of the process with our national search and interviewing is ongoing. As acting CFO, I am looking forward to the time of my conclusion to this search, but understand the importance of making the right hire over simply filling the position.
Now, I'll turn the call over to Tina Castio, our Controller to run through the numbers before I finish up with some comments about the outlook for the remainder of 2009 and into 2010.
Revenues for the three months ended September 30, 2009 totaled $35.2 million or $17,592 per revenue day compared to revenues of $82.4 million or $17,093 per day in the third quarter of 2008. The increase in average dayrate is primarily due to $428 of revenue per day generated from the two rigs on stand-by as well as decreased utilization of our smaller rings which earned a smaller dayrate.
Operating costs for the third quarter totaled $22.3 million or $11,167 per revenue day compared to $52.5 million or $10,879 per day in the third quarter of 2008.
Drilling margin totaled $12.9 million or $6,425 per revenue day compared to $30 million or $6,214 per day for the third quarter of 2008. Our aggressive cost control has allowed us to maintain a respectable average daily margin, despite a 59% decrease in the number of revenue days this quarter compared to last year.
While we do anticipate putting some outer rigs back to work this quarter and in first quarter of 2010, this will likely reduce average margin initially as we take care of differed maintenance and mobilization cost on these rigs prior to earning any revenues. Additionally, some rigs rolling off term contracts have been and will continue to reprise at current market rates.
Speaking of term contracts, we currently have 17 employees, including two that are on stand-by and earning total revenues. During the third quarter, while we have six contracts roll off as expected we also extended three of those and added two more. We do expect the power contracts will roll off during the first quarter of 2010 and another three will roll off in the second quarter of 2010 and additional three contracts are scheduled to end in the second half of 2010.
Back to the income statement; general and administrative expenses decreased to $5.8 million compared to $8.6 million in the previous year’s third quarter. The majority of the reduction in G&A came from reduced payroll expense and bad debt expense. Specifically, our bad debt expense was almost a $1.5 million lower in Q3 ‘09 compared to the prior year.
Third quarter EBITDA totaled $6.8 million in 2009 compared to $22.6 million in 2008. Depreciation and amortization for the quarter totaled $12.2 million, up from $11.6 million last year, reflecting our four new rigs that were placed in service in the first half of 2009.
We reported a net loss for the quarter of $4 million or a loss of $0.17 per share, compared to net income of $5.9 million or $0.27 per share in the prior year period. Keep in mind, since the end of last year’s third quarter, we completed 18 million share repurchase and a 3 million share offering for a net increase of 1 million shares.
On the balance sheet, we had $10 million drawn on our revolver as of September 30th, compared to $24 million on June 30th and $43 million at the beginning of the year. The substantial decline this quarter was a result of generating positive cash flow from operations, combined with minimum capital expenditures.
Also our cash intake was due to about $6.4 million refund from the IRS, as a result of accelerated tax depreciation taken on our 2008 tax returns, as well as a $500,000 refund of workers comp premiums given on our headcounts.
Cash used for capital expenditures during the third quarter totaled $1.7 million, all of which was designated as maintenance CapEx. Our revolver balance is likely to rise in the fourth quarter, key to expenditures associated with putting rigs back to work, as well as, the annual prepayment requirement of our insurance premiums that are due in December.
I’ll now turn the call back over to Chris Strong.
For the first time in several quarters, I’m pleased to report that things are beginning to look better. Operators in our markets are describing plans to ramp up rig count in 2010 and our telephone traffic related to various programs is up substantially.
We are not out of the woods yet, but oil prices have been strong for several months now, and there is a growing perception that natural gas which is recovered from inflows will have better dynamics going forward.
Our utilization increased gradually throughout the third quarter and we expect to continue adding rigs in the fourth and first quarters. However, this increase in rig count utilization may not result in immediate increase in earnings. We have several rigs coming off term contracts in the first quarter at rates that are not currently available.
So increased utilization maybe offset by decreased average margin per day. Even though, it will negatively affect near-term results. I have not been oppose to negotiating term contracts in the Marcellus, that entail, including some of the mobilization costs to move rigs from our other markets in the Pennsylvania.
Finally, although the rigs have not been down long enough for there to be substantial deferred maintenance, they’re always some initial costs associated with putting a stacked rig back to work.
With our clean balance sheet, access to capital, in the depressed state of the rig market, I have had the opportunity to look at quite a few rig deals in both domestic and international markets. Much of what is available is at best white cycle iron that is not going to find a customer in the current market. And therefore it will have a hard time finding a buyer.
With our large historical footprints in Appalachian and what looks like the biggest, lowest cost gas play in the country developing there, I believe meeting expanding customer demand in the Marcellus Shale is our best growth opportunity and use of capital.
One of the rigs we refurbished in Texas last year is on its way to Pennsylvania for a one-year contract and I believe there will be more in the near future. We are having ongoing conversation with operators that have acreage positions in the Marcellus to determine what types of rigs they need now, as well as, in the future.
There is currently work for smaller rigs to drill vertical wells or drill the vertical section on air ahead of other rigs that don’t have the [wreckage] or equipment for under balanced drilling, but this is a short-term niche and not a place to deploy additional capital.
Walking and skidding systems will be in greater use as the play moves from exploratory to developmental. But they are not essential to have on every rig right now, and can be put on the rigs sub-structured fairly easily, when the demand increases. In fact, we are in the process of putting walking systems on three more of our Barnett Shale rigs, because we anticipate there will be increasing demand for rigs that can efficiently drill multiple wells on locations with the existing and declining productions.
Turning to the Marcellus; customers currently want to drill many individual wells and complete them to assess and hold their acreages. The rig that stays on location and only moves twice a year is out there, but not in the exploration phase. So, big equipments that has been moved from other areas to finish up an existing contract, can experience moving delays and result in less than ideal value for money.
There are some innovative built for purpose rig designs out there, but memories of multiyear contracts of high dayrates when the bottom fell out of the gas market are obviously very fresh. And while we're seeing the lot of interest in these designs, there is a reluctance to sign the type of contract that will provide the drilling contractor a reasonable return on capital.
As a result, we are looking at existing rigs in our fleet that have the equipment to do the work and can be moved fairly easily. If gas prices come back reasonably well, my guess is that the demand for rigs in the Marcellus will fairly quickly outstrip the availability of this type of rigs, and we will see fit-for-purpose new build opportunities in that market.
With that, operator we are ready to take questions.
(Operator Instructions) Our first question comes from the line of Mark Brown with Pritchard Capital Partners.
Mark Brown - Pritchard Capital Partners
Just if you could touch on little more of the smaller rigs in Appalachia, if you’re seeing more increased utilization opportunity in Q4? I guess how many rigs in the Appalachian do you think that are suitable for the Marcellus in your fleet?
Well, multi-part question Mark. We are seeing some more demand for the smaller rigs. We've got three rigs out right now on five day a week, coal projects for the coal companies. We also have some of the smaller-doubles that have been doing vertical [quick Madaina] type wells for years. Some of that work it looks like it’s starting to come back and we've had some discussions with long time customers about going back to the work in the non-Marcellus areas of the Appalachian Basin.
Basically, those five and 6,000 foot vertical gas plays up in Pennsylvania and Northern West Virginia. Not quite as much nearly going on with some of the horizontal coalbed methane work, we’re doing down in Southern West Virginia. I’ve been heard a whole lot about that recently that may come back, but it’s not something we're engaged in right now.
As far as rigs in the Marcellus we do have some of the again smaller or larger-double, say, 300,000 pound Hook Load rigs that are doing some the vertical work. We do have some larger rigs that have come in from other areas that as I said earlier are not necessarily equipped to do air drilling. They don’t have the air packages or more probably combination of both not having air packages or the crews that are trained. So, it’s often preferable to have a smaller rig come in and do the vertical section on air.
As I have said, I don’t really see that being a healthy long-term market that the larger rigs will probably eventually have the air packages and the market will be more balanced. We are pretty much out of our inventory of rigs in Appalachia that can do the Marcellus work as far as inventory up there. So that’s why we are looking at bringing rigs out of Texas and Arkansas into the market.
What we are seeing or what we are looking at moving right now, Mark, are the box-on-box styled triples that are a 1000 horsepower with 500,000 pound derricks and larger pounds either, 1,300 or 1,600 horsepower. That’s a rig that is movable because the boxes are about eight feet high and so if you have the box-on-box, you get up to a 16 foot to 18 foot rig for where you have enough height to get your well controlled equipment underneath it, but your loads when you teardown the rig or not, so think to make them hard to move around.
Mark Brown - Pritchard Capital Partners
I think Tina mentioned two new contracts and three extended contracts, can you give us any color on where those are and how long the terms are and the dayrates?
Some of it’s, Mark is kind of horse-trading at this point where you may trade a little bit of existing dayrate for some term. We’ve had opportunities to talk to customers that are actually adding rigs and maybe you cut the rate on one of your high-dollar term contracts in exchange for putting a new rig out under a term contract.
We’ve looked at some of the rigs in the Marcellus where there are additional opportunities to bring the rate down, give the customers another rig, a rig with a top drive for Marcellus drilling to get next few years, we’ve been looking at kind of 16 for the rig and another couple thousand for the top drive, so maybe rate is high as 18. Although, I will say there are prices out there in the Marcellus right now that are more like in the 14 range for a mechanical rig and maybe 18 for a higher spec electrical rig with a top drive. The portable doubles those are beefy enough to do the work maybe as low as 13,000.
It’s really in that market a question of which customer, do you have something to trade and maybe come down a little bit to secure some extra utilization and provide cash flows over 2010. We are really not seeing those sorts of opportunities down in Barnett Shale. We continue to have the term contract covered down here. We put a couple rigs out into West Texas, but that is an extremely competitive market and the only value that you can provide to customer out there these days seems to be price because the market is so highly commoditized. We are seeing rates sub-$10,000 on dayrates out there. There has been in certain areas the pushback from customers to attempt to get a footage, we have not done that at this point, but we do have a couple rigs out in West Texas now that are on pretty well dayrates where we really have to watch our costs to clear a couple thousand a day in margin.
The Arkoma, actually we’ve taken a rig over into Alabama to do some kind a spec drilling for a couple of different customers. I don’t know what was that, maybe [16.5] kind of rate. I don’t know if it’s the next Haynesville or somebody would certainly hope it is the next Haynesville, but we are doing some exploratory work over there for a couple of companies that have some acreage.
As far as the rest of the Arkoma, outside of some of the Fayetteville horizontal work we are doing, again with contracts banking them, the smaller triples in that market are down around 10.5 a day and the doubles are probably a shade under 10,000 a day.
Our next question comes from the line of Jud Bailey with Jefferies & Company.
Jud Bailey - Jefferies & Company
Chris based on your conversations with operators, can you give us a sense, how many rigs you could potentially move out of Texas and to the Marcellus, just a range, perhaps just to give us a sense of we are talking about one or two or as many as five or six.
You could be up at the five or six, if we have rigs that are suitable. First, we are looking at the rigs we spent some money on in the last year refurbishing the rigs. We put new drawworks, derricks and subs on. Those are kind of fresh iron, fresh power; those are more highly sort after. The one we’re moving up now is one of those rigs. We have a couple more in Texas like that. We’ve got one in Arkansas like that. I think the general parameters right now as far as the preferred rig is the 1,000 horsepower drawworks, and 500,000 pound [massed] with a pair of 1,600 horsepower pumps. We have the number of rigs that fit that are not the recently refurbished rigs. But you start getting in to issues with load sizes and frankly some what less appealing rigs.
So, we are also out there combing through the various distressed assets trying to identify some of the types of rigs that would fit. We’re also looking at some of the new build designs. But as I said earlier it’s very difficult in this market right now to get a customer really enthused about something in the mid-20s per day as far as dayrate and some number of viewers out to provide a return on capital. Now the rigs we’re looking at are probably in the 15 to $17 million range from new builds.
Now the economics for us just really don’t work at 20 and below a day. Yet, operators at least so far have been able to make do with rigs that are out there were particularly designed to be mobile in that environment but are doing the job more in say $16,000 to $18,000 a day range. I feel fairly good about the fact that we’ll be moving some more rigs up there. We’ve got multiple customers we’re talking about, and each one is talking about multiple rigs. I realize that Union Drilling isn’t necessary going to capture all of that market share, but there’s enough going on up there with enough different customers that I think we’ll capture some portion of it.
Jud Bailey - Jefferies & Company
Follow-on on your new build comment. Given the number of discussions that you’re having and how apparently stronger the demand is, it looks to be in the Marcellus for the foreseeable future anyway. Would you consider building a new rig, that didn’t have a three-year contract, in other words if you can get attractive one-year deal, would you contemplate that or is that a non starter for you at this point?
As such that an excellent question. I don’t know that one is the right number. I think we’ll certainly go down from three. What we were able to do in the Barnett when things were really hot was three-year contracts, with kind of three year cash on cash paybacks. Now, may be you have to take the dayrate down to something that stretches out the payback and also decrease the term contract cover. So, may be you do something down around two-year and also skinning the rate down enough, where you pushed out the return and well the return on capital, as well as the risk of not having a renewal two years out at a rate similar to what you put the rig to workout.
I think those are reasonable risks to take right now, and same sort of thing with the existing rigs Jud I think. Even if we hurt a quarter by incurring some upfront cost, to me it’s a lot easier to get in the incumbency and market share on the front-end then try and knock somebody out later. If that takes a little bit of priming the pump up front and we eat a little bit of cost on the front-end, I think this play is for real it’s going to be around for a while. So, those strategic moves to gain market share makes sense to me.
Jud Bailey - Jefferies & Company
My last question is on you mentioned you’re going to be incurring some CapEx, to may be put some walking systems and top drives on your rigs. Can you give us a sense of how much CapEx you could be spending doing those types of upgrades over the next couple of quarters?
Well we have three walking systems right now in process on our ideal rigs. Those are, I don’t know the sum of those maybe $5 million or so for the three of those. Top drives are running around $1 million maybe $1.3 million to $1.5 million a piece right now. Especially on the mechanical rig Jud, the electric rigs, we have a mix down here in the Barnett with our electric rigs, between rigs with top drives and rigs without.
The mechanical rigs it’s really essential to be able to the horizontal drilling because the top drive separates the rotating from the hoisting on a mechanical rig, whereas in an electric rig you have separate motors controlling those functions anyway. But, we absolutely will have to have top drives on rigs that we put walking or skidding systems on. If you are pulling out 90 feet of pipe at a time and standing it up in the derrick with the intent of moving the rig with all that the pipe in the derrick, you need that top drive up there to go back in.
So, we’re thinking about rigs that have to have top drives and then rigs that can be modified as we move more into the pad drilling. As I said earlier, I’ve talked to both small and large customers up in the Marcellus, and right now the appetite is to drill the single well and move to the next location to prove up anchorage to hold leases to determine, what are the high-graded prospects on the acreage positions and then come back later and may be do three or four wells, but nobody seems to want to drill eight or 10 wells before you do a frac and find out what you have.
We're still in this area where the mobility of the rig is really important and then coming back in a year or 18 months when you start to have some sort of decline curve on the well and determined that you would like to come back and drill three or four wells, you need a rig design that can fly it over the existing wellheads that’s on the location. So that may lend itself actually to the older style box-on-box rigs with some sort of walking or skidding system to be able to go over the cages that are put over the wellheads.
Jud Bailey - Jefferies & Company
Tina, would you mind repeating the rollover schedule that you mentioned in the call? I didn't catch the last couple of things that you said.
We said in the 21 last quarter, we had six roll off as expected. We extended three, and added two more.
Jud Bailey - Jefferies & Company
How many do you have rolling off in the fourth quarter?
We don't anticipate any rolling off next quarter. The five were rolled off during the first quarter of 2010 and another three in the second quarter of 2010, and then three in the second half of 2010.
Our next question comes from the line of Victor Marchon with RBC Capital Markets.
Victor Marchon - RBC Capital Markets
Just as a follow up to the last question on the rigs that are rolling off. Chris, how should we look at the margins for the rigs? Is it sort of a ballpark on the average for the rigs that are going to be rolling off between now and the end of 2010 relative to where the spot margins are right now?
Victor that's the reason we don't have a lot of debt on the books by designs because you have lot of rigs that are coming off that’s been spinning out 10,000 or more a day at margins and even though, some of the small rigs are going up for which may be you’re looking at 2,000 a day of margin on some of the rigs that have not have term contract. May be these term contract rigs, the bigger electric rigs when they come to the end of their three-year deals, I don’t anticipate they will go out of 2000 a day and may be they will pick-up four or five, but they’re certainly not going to pick up 10, 12 or 13 a day.
That’s the issue that you may have utilization come up nicely, but how many quarter’s until you get some decent pricing power. I guess that also kind of rolls into the concept of what you do with that still expensive recently built electric triple that a customer says, well, okay, now I will take it for a year or two at 14 a day. Do you really want to leave it the amount of time on an extension at what is a very low margin?
Victor Marchon - RBC Capital Markets
You suggest looking at it from a modeling perspective, so you could say around 10,000 high single-digits to 10,000 for [retailer] going to rolling off and going anywhere from low single to mid single-digits on the rollover, assuming spot pricing doesn’t move from current levels?
I think that’s right.
Victor Marchon - RBC Capital Markets
As it relates to the spot market, has pressure sort of alleviated? Have we hit a bottom on pricing? And the second part to that question, this is relates to what you said about the Marcellus, you could end up being short rigs there, do you get sense that you could see some bifurcation in the market? Going forward with certain regions, you start to see some pricing power for other regions or may be by asset class, some asset class to see pricing for others?
Absolutely. I think we are there right now, Victor where West Texas as I said, we got some workout there and the wells at $75 or $80, but there are so many rigs and so many people out of work out there that there is demand, but there is still no pricing power. Obviously on the other side of the spectrum for Union Drilling, there is the Marcellus where you still have some inflation and the people who want to drill, either have to get rigs in, that may not be exactly what they want or they pay a premium because the market is not oversupplied right now. So, you have that bifurcation geographically.
I think you are probably right too on the type of equipment that, some of the equipment is just not going to be entirely sort after and that's part of why we’ve decided to spend some capital while things are slow, here in the Barnett, that we think the equipment demands are going to evolve here in the Barnett, so walking rig design that can go back onto an existing location and around existing wellheads that are on location, that's going to command more of a premiums in a rig that was not designed with those features.
I think because of the declines of the wells in the Barnett that were obviously a lot closer to re-entry type work on existing paths where location has already been paid for the gathering systems running there, but the productions falling off, so does it make sense if you haven’t recovered all of the gas in plays to go down and then side track the original wellbore, may be with multiple additional wells and refrac on that location and get the production back up into that pipeline. So, that’s what we’re thinking about as far as investing capital in rigs that are idle here in the Barnett for a recent to bifurcate those rigs from what the other people will be offering as gas prices turn up.
Victor Marchon - RBC Capital Markets
Could you give a current breakdown just by region of the fleet and just within the Appalachian segment how many of those rigs would you say can do the Marcellus horizontal type of work?
Well, 71 rigs fleet essentially. We’re going to be at 32 up in Appalachia after we move the rig out of Texas. So, I guess we’re going to be down with 19 in Texas and then 20 over in the Arkoma. As of today, we’ve got 28 rigs running. So we are about 39% utilization. Best utilization right now is in Appalachian near 50% and then Arkoma and Texas are in the low-30s. I’m not sure if I answered your question there, I got off on a little bit of a [tangle].
Victor Marchon - RBC Capital Markets
Just to do a follow up to that was, within the 32 in Appalachia, what’s sort of a split between the rigs that are focused on whether it’s vertical well in the Marcellus or the non-Marcellus Shale natural gas drilling versus the horizontal type of work?
Yeah, we have a couple of rigs that are kind of on the border about 370,000 pound Hook Load rigs. So, let’s say we probably got, 10 that could qualify, although a couple of those are kind of on the border with people really looking at 500,000 pound rigs right now.
(Operator instructions). Our next question comes from the line of Max Barrett with Tudor, Pickering, Holt & Co.
Max Barrett - Tudor, Pickering, Holt & Co.
Most of my questions have been answered. But just going forward as we think about sort of blended average, operating expenses per day, is there room to take additional cost down or do you think that sort of 11,000 is reasonable going forward?
We’re certainly below that on the smaller rigs, I mean given some of the rigs that are out at 10,000 or even in the high nines, you’re obviously squeezing cost to be able to have cash flow out of those rigs. Probably say, you might have a similar turn down on some of these larger rigs that have come off contract that. Customers if you are getting north of 20,000 a day, you better have the people out there to be, may be the fifth man or even the sixth man out there.
You are being expected to provide catalogue services at those rates right now. If you’re talking about that rig becoming repriced at a far lower rates, I think you got to go back to cruise and back to the customer and rationalize the lower rate. So, I don't know if there’s a whole lot to be squeeze out. I mean we are not that far out in terms of our weighted average operating expense per day from the other public drillers, but, I think there is probably some at the margin, but I wouldn’t count on a whole lot.
Max Barrett - Tudor, Pickering, Holt & Co.
Then given the sort of recent improvement in that gas, do you expect that the rigs currently on standby will stay on standby or whether they would start working soon?
Well as I said on the earlier conference call scripted comments, we are putting rigs out. We anticipate we’ll put more rigs out in the fourth quarter and in to the first quarter. So, we’re getting the telephone traffic. I think we’re going to see utilization improve. I don’t know that today is good proxy for the whole quarter, but we’re up shade under 40% utilization in the fleet today. We are probably going to see some of the traditional holiday slow down, hunting season up in Appalachia those kinds of things that will probably put a little drag on the quarter in terms of utilization.
But the trend is definitely up and as I said the telephone traffic is up, and the number of rigs we’re looking at putting out is up. So, I hope it’s not the double-dip or something like that and that this is really coming off the bottom and as you come of the bottom you don’t have any pricing power. But then as utilization improves, eventually you return to pricing powers as well. That could really take a few quarters which as I said earlier is one of the reasons to have a clean balance sheet in this business.
Thank you. There are no further questions at this time. I would now like to turn the call back over to management for any closing statement.
Well thank all for your interest in Union Drilling, and we will talk again after we have our year-end results early next year. Thank you very much.
Ladies and gentlemen, this concludes the Union Drillings third quarter 2009 earnings conference call. You may now disconnect. Thank you for using AT&T teleconferencing.
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