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Executives

Larry Pinkston – President and CEO

Brad Guidry – SVP of Exploration, Unit Petroleum Company

David Merrill – CFO and Treasurer

Analysts

Marshall Adkins – Raymond James

Pierre Conner – Capital One Southcoast, Inc

Andrew Coleman – UBS

Unit Corporation (UNT) Q4 2008 Earnings Call Transcript February 24, 2009 11:00 AM ET

Operator

Good morning, my name is Octavia and I'll be your conference operator today.

This conference call contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act. All statements, other than statements of historical facts included in this call that address activities, events or developments that the company expects or anticipates will or may occur in the future are forward-looking statements. A number of risks and uncertainties could cause actual results to differ materially from these statements, including the productive capabilities of the company's wealth, future demands for oil and natural gas, future drilling rig utilization and day rates, the timing of the completion of drilling rigs currently under construction, the ability to contract new rig additions to its fleet, projected additions and date of service to the company's drilling rig fleet, projected growth of the company's oil and natural gas production, oil and gas reserve information as well as the ability to meet its future reserve replacement goals, anticipated gas gathering, and processing rate and throughput volumes, the prospective capabilities of the reserves associated with the company's inventory of future drilling sites, anticipated oil and natural gas prices, the number of wells to be drilled by the company's exploration segment, development, operational, implementation and opportunity risks and other factors described from time to time in the company's publicly available SEC reports. The company assumes no obligation to update publicly such forward-looking statements, whether as a result of new information, future events or otherwise.

I will now turn the call over to Mr. Larry Pinkston; you may begin your conference.

Larry Pinkston

Thank you Octavia. We want to thank you for calling in and welcome to Unit Corporation’s fourth quarter and year end 2008 conference call. With me today, I have David Merrill, our CFO; Brad Guidry is Senior VP of our Exploration for Unit Petroleum; John Cromling, Executive Vice President of Drilling operations; and Bob Parks, President of Superior Pipeline Company.

We released our fourth quarter report to the public this morning. I will spend a few minutes recapping Unit Corporation’s fourth quarter and year-end 2008 results versus 2007; I will also provide you with an update of Unit Drilling and our mid-stream operations. Brad Guidry will discuss the details of our E&P operations and David Merrill will discuss key financial facts and figures. We will take questions after our comments are completed.

2008 was quite a rollercoaster ride. The year started off on the slow side gaining momentum during the late first quarter, drilling rig activity became very frantic during the second quarter as a result of the run-up in commodity prices and for the most of the third quarter activity was stable to slightly rising. In the fourth quarter we went through a major loop in the industry meaning in a completely upside down position. I don’t want to entirely focus the discussion on just one quarter, 2008 in so many respects was a record-setting year for us. Our revenues were the highest in company history, 17% better than 2006 which was our previous record. If we exclude the impact of the year-end oil and gas reserve impairment, our net income would have been an all-time record. Our rig count is currently at 132, an all-time record. Our oil and gas reserves reached an all-time high of 569 Bcf equivalents, which is up 11% over 2007 and this growth was in spite of losing 23 Bcfe to lower pricing of our 2008 reserves. Our oil and gas production increased 16% over 2007 another all-time record. Our operating profit before depreciation and amortization for our mid-stream operations increased 66% in 2008 versus 2007.

Moving first to our contract drilling segment, we averaged operating 103 rigs for the year, a 4% improvement over 2007. Our average day rate was $18,500 per day, $200 per day less than 2007. Our average daily operating margin was $9000 per day, down $600 per day from 2007. In the fourth quarter we averaged 97 rigs operating down 14 rigs from the third quarter, our average day rates for the fourth quarter were $19,330 per day, up $700 per day from the third quarter and our operating margins for the fourth quarter were $9500 a day, up $200 from the third quarter. Our rig utilization steadily decreased during the fourth quarter as operators cancelled drilling plans as a result of the rapid deterioration of commodity prices and the lack of availability access, equity or debt markets.

The decline in reutilization has continued thus far into 2009, we currently have 55 rigs under contract; current indications are for the rig count for us in the industry to decline at least through the first quarter. We are focusing on the factors over which we have the most control which is the cost side of the equation. We are delaying capital expenditures on rigs without immediate demand. Late in the fourth quarter we reduced our field labor cost for Oklahoma and Texas rigs by approximately $350 per day. We have consolidated three field offices into other existing offices. We currently have plans to bring out one additional rig during the fourth quarter of 2009. We had the major components for nine additional rigs on order in the fourth quarter. We have cancelled the orders for three of those rig packages and are taking the major components for the other six rigs. We have deferred the completion of these six rigs until demand returns. We have substituted existing available rigs for three of the deferred rigs and we will be receiving contract cancellation penalty payments for three other rigs.

In our mid-stream segment, financial results for the fourth quarter slipped compared to the third quarter. The drop was due to the substantial decline in pricing for natural gas liquids, the realized price for ethane [ph] in December was well below its equivalent gas value per MMBtu causing us the reduced recoveries of ethane at various gas plants as did most other mid-continent based processes. Entering 2009 liquid prices are higher than the fourth quarter of 2008 but they are nevertheless at the price levels along with the rest of the energy product complex. Volumes of gas gathered during the fourth quarter were down 4% compared to the third quarter.

We started up a newly constructed gathering system in the fourth quarter and executed agreements for the construction of an additional system in the mid-continent. That system is currently under construction. Business development efforts for our mid-stream operations in Appalachia continue although Marcellus Shale exploration also has slowed down or been delayed until late 2009 or 2010. Several possible projects based upon existing traditional Appalachian production are being evaluated.

I will now turn the call over to Brad Guidry who will review our exploration and production results and then David Merrill who will recap the financials. Brad?

Brad Guidry

Good morning. We had a very successful drilling program in 2008 with 278 wells being completed at an 88% success rate. While the gross well count was only up a modest 10% compared to 2007 the equivalent net well count jumped up 42% indicating a shift towards drilling higher interest unit operated wells.

In 2008, we operated 153 wells which is a 70% increase over last year and we utilized unit rig on 79% of the 153 wells. Another trend that is reflected in the 2008 well count is its significant increase in the number of horizontal wells we drill. After operating only two horizontal wells in 2007, Unit operated 17 horizontal wells in 2008 that targeted various reservoirs including shale, coal, and sandstone reservoirs. The early production results from the majority of these horizontals appeared favorable as compared to the vertical wells but we do need additional time to fully evaluate the most favorable economics for each play.

I will now go over some operational highlights that occurred in several of our significant plays during 2008. Our Granite Wash and Morrow Play in the Texas Panhandle was once again our most active area for 2008 where we drilled and completed 42 gross wells at a 97% success rate at an approximate net cost of $70 million. Net daily production for the fourth quarter of 2008 increased to an average of 21 million cubic feet of gas equivalent or 9% increase compared to third quarter of 2008 and 118% increase over the fourth quarter of 2007. We drilled and completed our first horizontal well in the Granite Wash during the fourth quarter and it is performing very well in producing at a current rate of 4 million cubic feet of gas per day and 120 barrels of oil per day with 750 pounds flowing tubing pressure.

Based on the positive results from this well we anticipate horizontal drilling will play a significant role in our future development of our Granite Wash prospect area. We plan to spud our second Granite Wash horizontal well in the second quarter of 2009. With the continued decline in gas prices we currently only have one Unit rig running with plans to add a second rig midyear which will result in the drilling of approximately of ten vertical wells and two horizontal at a net cost of approximately $24 million for 2009.

In our Segno prospect located in the Texas Gulf Coast, we had an outstanding year. We completed 15 new wells at 80% success rate at an average working interest of 86%. We spent approximately $50 million and added 31.5 Bcfe which resulted in $1.59 finding cost. Although our initial Segno field discovery was over five years ago, we are still establishing significant new production from previously untested zones such as the shallower upper Wilcox oil and gas sands located at approximately 8400 to 9500 feet. Due to these rigs in completion we were able to convert 12.5 Bcf in 1.4 million barrels of oil that were previously classified as probably hind pipe reserves to be classified as proved reserves. Out total acreage position in this Segno prospect area is approximately 85,000 gross acres, 66,000 net acres. For 2009, we plan to drill approximately ten wells at a net cost of $25 million to $30 million.

Moving to the Shale plays, in the Marcellus Shale we are at total depth on the first vertical well that is located in our Somerset County Pennsylvania prospect area and that well will be tested over the next several months. For 2009, we plan to drill two to three additional vertical wells in this area and then one horizontal well. We own approximately 180,000 gross and 55,000 net acres in the Somerset prospect area and then along trend to the north in Pennsylvania, in the Northeast Pennsylvania, we own approximately 25,000 gross in 12,500 net acres in Wyoming County. We anticipate to drill the first well there that will begin near the end of this year or early 2010. In East Texas, we had our first gas sales last week on the initial vertical Haynesville Shale well that is located in Shelby County.

We own a 60% working interest in this well. The sample number one is currently selling gas at an encouraging rate of 700 Mcfd with 3200 pounds of flowing tubing pressure. Since that time we have also drilled two additional vertical wells that are currently awaiting completion and then we have two unit rigs working right now drilling vertical wells in this prospect. We plan to drill our first horizontal Haynesville well in the second quarter of this year. Current plans are to drill approximately 15 vertical wells and two horizontal wells which will be an approximate net cost of $35 million to $40 million. However these plans may be revised depending on the outcome of the horizontal wells and the current market conditions. We own approximately 30,000 gross acres, 15,500 net acres in our core Haynesville area in Shelby and Harrison County in addition; we own approximately 15,000 gross, 3700 net acres in Ross and Cherokee County Texas which is currently unproven but potentially perspective for both the Bojer and the Haynesville.

In conclusion, we are pleased with the results obtained by the petroleum company for 2008. Our employees did an excellent job ramping up activity in the first part of 2008 as well as quickly and efficiently reducing activity as oil and gas prices collapsed in the fourth quarter. 2009 will be a challenging year but we are still excited about the opportunities we have in our inventory including the Haynesville and Marcellus Shale, Granite Wash and the Segno Wilcox which those four plays will be the majority of our 2009 spending. Our near term focus for future prospects will be primarily on horizontal drilling projects and shallow oil prospects. We have also increased our focus on reducing drilling and completion costs, improving our operating efficiencies and continue to reduce our LOEs. These efforts are particularly important in this low-price environment but will also benefit us when product prices rebound.

I will be available for questions at the end of the call and I will now turn the call over to David Merrill.

David Merrill

Thank you Brad and good morning everyone. As Larry mentioned earlier, 2008 was a tale of two halves of the year, the first half was at a record setting pace and the second half and in particular the fourth quarter was reflective of the carryover impact of the hurricanes followed by the deteriorating US and global economies combined with a lack of access to financial markets.

For the year ended 2008, Unit achieved all-time records for total revenues of $1.4 billion and EBITDA of $754 million. Excluding the impact of the ceiling test write down of $282 million, pretax $175 million after tax recorded in the fourth quarter due to the significant lower commodity prices on December 31, 2008 net income and diluted earnings per share would have been all-time records of $319 million and $6.80 respectively. EBITDA for the fourth quarter of 2008 was $157 million a decrease of 25% from $210 million in the third quarter of 2008 and a decrease of 6% from $167 million in the fourth quarter of 2007. For the fourth quarter of 2008, the oil and natural gas segment contributed 50% of EBITDA; contract drilling contributed 48% and mid-stream 2%.

EBITDA for the fourth quarter decreased from the third quarter in spite of a 6% sequential increase and equivalent daily production volumes in the oil and natural gas segment and a 2% increase in the per day operating margin (inaudible) company profit illumination in the contract drilling segment. The decrease was primarily due to a 32% reduction in the price of natural gas received, a 58% reduction in the price of NGLs received and a 24% reduction in the price of oil received in the oil and natural gas segment along with a decrease in average drilling rig utilization from 85% in the third quarter to 74% in the fourth quarter in the contract drilling segment.

For the oil and natural gas segment, basis differentials in the mid-continent during the fourth quarter continued to deteriorate from the third quarter levels. For the fourth quarter of 2008, basis differentials for our oil and natural gas production before the impact of hedges averaged $2.22 reduction from NYMEX whereas in the third quarter the differential averaged $1.53 reduction from NYMEX, approximately 70% of our natural gas production is delivered at Centre Point East and Panhandle East where differentials averaged $2.94 reduction from NYMEX during the fourth quarter of 2008 widening 49% from the negative differential of $1.97 during the third quarter while the 2009 features indicate the average basis differentials for Centre Point East and Panhandle East as approximately $0.94 from NYMEX we all realize the NYMEX future price has continued to weaken and looks to be headed towards weaker levels.

We have hedged approximately 70% of our 2009 natural gas production based on fourth quarter 2008 average daily production volumes at a weighted average delivery point price of $6.43 and we have edged approximately 72% of our 2009 oil production based on fourth quarter 2008 average daily production volumes at a weighted average price of $61.49. For 2010, we have hedged approximately 47% of our natural gas production based on fourth quarter 2008 average daily production volumes at a weighted average delivery point price of $6.60. We do not currently have any oil hedges in place beyond 2009 and our hedge position is up significantly from where we were at the end of the third quarter of 2008. More detail on our hedges is disclosed in our Form 10-K being filed with the SEC later today.

Operating segments capital expenditures for 2008 were $721 million excluding acquisitions. For 2009, our operating segment capital expenditure budget is $290 million, a 60% decrease from 2008 and does not include any amounts for acquisitions. Capital expenditures by segment for 2009 are $200 million for the oil and natural gas segment, $77 million for the contract drilling segment, and $13 million for the mid-stream segment. The 2009 capital expenditure budget is anticipated to be funded from cash flow from operations. The effective income tax rate for the 2008 fourth quarter and year was 37.8% and 36.3% respectively.

We currently estimate the effective income tax rate for 2009 to be 37.3% with 80% projected to be deferred. Unit has a debt-to-capitalization ratio as of December 31, 2008 of 11% with $199.5 million in long-term debt outstanding. Unit has a $400 million credit facility of which we have elected to have a current commitment amount available of $325 million. The credit facility matures in May of 2012 and our working capital at the end of the fourth quarter was $90.2 million.

Octavia, I would now like to turn the call back to you to open it up for questions.

Question-and-Answer Session

Operator

(Operator instructions) Your first question comes from the line of Marshall Adkins, your line is open.

Marshall Adkins – Raymond James

Good morning guys. Could you give me just some insight on where you see the rig count going, you mentioned I think I heard 55 working rigs right now, help me to understand where the costs are going and where rates are going right now and kind of where you think they may go over the next quarter or so. I know oil can’t go through the end of the year because it is a moving target but just kind of directionally where you see things heading short term on rates, rig count, costs, etc?

Larry Pinkston

Marshall, you know the right of decrease on our rig utilization is starting to slow down, we are not getting calls from the operator cancelling wells like we were through November, December and January so it is slowing down the rate of decrease, I think utilization is going to continue to decrease gradually from what we see right now through the first quarter rates are coming down not to the magnitude we have seen, utilization fall but they are coming down. I don’t know what the amount over the next four, five months is going to be to come down, a lot of our operators were telling us, as we are on our E&P side that everybody is starting the year off very slow expecting the second half of the year to be much more active than the first half of the year of course that is all contingent on what the commodity price is in the meantime but a lot of people are at their budgets that are not committed at this point but the rate of decrease, utilization is going to come down at least through the first quarter not nearly to the magnitude of what we saw in the fourth quarter in January that it is going to come on down.

Marshall Adkins – Raymond James

You mentioned your cut cost but historically rarely do we ever see anyone be able to cut cost fast enough on the way down to avoid the cost per rig actually seems to increase as utilization falls quickly, what is happening with you guys?

Larry Pinkston

At the end what happens is you have a certain amount of fixed cost, indirect cost that continue to go on no matter whether you are running 50 rigs or 80 rigs or you start spreading those kind of cost factors over a few number of rigs running and it increases your per day cost. On the direct cost side, we had the labor rate decrease for the two major sections of our rig market about $350 a day and that happened at the end of December so none of that was reflected in the fourth quarter. We are bringing out all of our old files on these kind of times, we are looking at things like getting a downtime insurance rate on when our rigs are down versus playing full stream, property tax reductions and all those kind of things take a little bit of time. First quarter rig cost per day, we always see cost in the first quarter a little bit higher because of the all the taxes that roll over other than being all set by the $350 a day, those kind of costs are going to be higher in the first quarter than they were in the fourth quarter but costs are coming down. Our vendors are reducing cost, not to the magnitude we would like to see them yet but the costs are coming down not to the magnitude that we have seen a decrease in day rates.

Marshall Adkins – Raymond James

So is it fair to say your cost per rig is still drifting a little higher?

Larry Pinkston

Yes on operating rigs, yes.

Marshall Adkins – Raymond James

Alright, last one from me, you had some big differentials this quarter, gas prices have fallen, is there a price that you have just shut in production, you have done a phenomenal job hedging and could you just cash in the hedges and shut in wells at the same time, walk me through how that would work in your mind?

Larry Pinkston

Well, just because we have our gas hedged it does not mean that we need to produce it, that was a concept that we basically never considered in the past that is the concept that we – we are kicking around to make sure we know all the ramifications if we do this from the accounting standpoint. We shut in gas in October in Southeastern Oklahoma when it went – we had some periods when it down to less than $1 in Mcf and we are not going to sell gas at that level whether we have got hedges or not. But, you know, I remember back in the early ‘80s when there were comments to say that we will never sell gas below $2 per Mcf and for about 15 years we were tickled by this to get $2 in Mcf for gas. I am trying not to make those statements as we will never produce below a certain price because it usually tends to come back to haunt you.

Marshall Adkins – Raymond James

But it sounds like, as you sit here today, if it falls down to below $1 you are shutting in, is that a fair –

Larry Pinkston

Unless you are being drained or you have other field considerations to take into account, we see no reason to sell gas to below $1 in Mcf.

Marshall Adkins – Raymond James

Got it. Thanks for the help guys.

Operator

Your next question comes from the line of Pierre Conner, your line is open.

Pierre Conner – Capital One Southcoast, Inc

Good morning gentlemen.

Larry Pinkston

Hi Pierre.

Pierre Conner – Capital One Southcoast, Inc

Hi, actually the first question for Brad, any update or activity planned in the Balkan at all and Woodford were two that you had not mentioned that they moved down on the list in terms of what should we be working on and do you have some small plans in those areas?

Brad Guidry

Yes as far as the Bakken Pierre, we are in a non-off position on a majority of our leaseholds there. We participated in about 17 wells in 2008, toward the end of last year, the oil differentials up in the Bakken play got up as high as $20 a barrel and the operator was up there as things started shutting down. Then in the plans for the Bakken for this year, those differentials have come back down to around 10 or a little bit less and that is the start back drilling probably in April of this year. So the position that we are in out there, the results we have had have been good. It is just from a non-op position we are trying to talk about more of the things that we control at this point.

Pierre Conner – Capital One Southcoast, Inc

Okay but you think they will start it back in April.

Brad Guidry

Okay, yes the Woodford we drilled two horizontal wells out there that we have operated, the first well is online still, has been now for probably four or five months. We just putting it on gas worth, we have not recovered all the load back at this point but the well is making between 400 Mcf and 500 Mcf per day. When it stays unloaded, it will make as much as a million a day. So we are still in the evaluating stage of that. The second well we drilled was a little bit deeper, horizontal Woodford well, we have one stage fraced [ph] here in the last two or three weeks and we have two stages left to frac. So we will have something to report on that. And then for 2009, we are not planning to drill any Woodford wells at this time.

Pierre Conner – Capital One Southcoast, Inc

Okay and at least some of this, could you go through again your completion on your Haynesville Well and that rate I guess is still unloading. You had 700 in a day I believe.

Brad Guidry

Yes that well, Pierre, we drilled that last year probably in the summer and it has taken a long time to get the well on. The well literally just had first sales last week so the rate I was talking about was what we sold gas for a couple of days ago and with 3200 pounds at this point they are just opening the well up slightly. You know, it is a vertical well; we are encouraged that the well is making 700 a day with 3200 pounds. In Shelby County activity we have out there, there has been a lot of recent activity around us by other operators that are drilling horizontal and I think over the first half of this year you will start seeing some results and we will get some hard data we will be able to talk about but everything in that Shelby County area right now looks pretty encouraging and as I mentioned, we will plan drilling our first horizontal in the second quarter of this year. Part of the reason we are drilling so many verticals in that Shelby County is it is a leasehold issue; we are putting the units together to try to save our leasehold out there which expires during part of 2009. So it is more of a strategic move, plans in the future will be to develop most of the (inaudible) that we have in a horizontal fashion.

Pierre Conner – Capital One Southcoast, Inc

Okay. On the operating side, what do you think your LOE can do, from here I was seeing a 30% and 40% decline in the completion cost, but on the operating expenses, how can we think about how much of a decrease we could expect?

David Merrill

Pierre this is David.

Pierre Conner – Capital One Southcoast, Inc

Hi David.

David Merrill

Yes, in the fourth quarter all in operating expenses were around $1.54 in Mcf equivalent and that was down from $2.02 in the third quarter and the fourth quarter had some adjustments in it that won’t be reoccurring so we ought to see an Mcf equivalent around $1.70ish in the first quarter and I am not talking about it specifically but Brad did not have an opportunity to mention it but our costs are definitely coming down. So to the extent that those are continuing to materialize that ought to be reflected in a go-forward grade beyond what I told you about the first quarter.

Pierre Conner – Capital One Southcoast, Inc

But we are talking about in (inaudible) as opposed to completion cost coming down significantly more, we are not going to see the nag until you could decrease the health [ph] rate?

David Merrill

Correct.

Pierre Conner – Capital One Southcoast, Inc

Okay, fine. Back to the rig count I guess, I know Marshall asked this but I will try to ask a little differently, you are at 55 rigs running now and I would imagine if some indication for most operators, where could you project maybe a negative rig for the quarter, do you know that you have noticed that a certain number of those will be laid down –?

Brad Guidry

You know the thing is making it hard right now to do projections, we are back in the market picking a well here and a well there, a contract to drill two wells and it is easy to project rig utilization when you have got a customer that has got a six or nine-month commitment to drill wells but the environment we are in right now, not all surprises that we are getting is all negative surprises when we are keeping rigs. So that changes quickly, it is much harder to forecast – some of our rigs that are running now, we know that they are coming down between now and the first quarter. We know some others that are coming up but it is very difficult right now, it is not in the neighborhood of 20% one way or the other, I mean, we are talking about a few percent here and there and we are back in the environment where it is very difficult to project whether – will you pick up two rigs, will you lose two rigs or you are gaining three rigs.

Pierre Conner – Capital One Southcoast, Inc

Okay, actually that is fine and back again on the day rate question, my thinking was during this first quarter you really did not have an option of reducing rates, it was working or not working, so my question is ones or twos that you might be picking up here, where is the leading edge day rate being discussed where you might actually get someone that is calling you on a potential well drill?

Brad Guidry

Well it depends on what size rigs you are talking about but let’s take a 1500 horsepower rig, from the peak to where we are now on day rates for those which the peak was back on the third quarter early fourth quarter, you are talking about 4000 to 5000 a day decrease.

Pierre Conner – Capital One Southcoast, Inc

Okay, that is helpful. Very good gentlemen, I will turn it back, thanks for your help.

Brad Guidry

Certainly.

Operator

Your next question comes from the line of Andrew Coleman, your line is open.

Andrew Coleman – UBS

Hi, good morning folks.

Larry Pinkston

Good morning Andrew.

Andrew Coleman – UBS

I had a couple of questions, clarifications first on a revolver that was $325 million with $189 at year end and $90 million of working capital so about a $30 million cushion?

David Merrill

$30 million cushion, no, it will be much larger than that.

Andrew Coleman – UBS

Okay.

David Merrill

You know you take the $325 million less the $200 million, so that is $125 million to begin with and then you add the $90 million to that.

Andrew Coleman – UBS

Fair enough. And then looking at the E&P rig count, can you tell me where it peaks with you guys, your operator rate count on the E&P side last year and kind of where you guys are currently sitting?

Larry Pinkston

Rig count peaked to about 117, 118 rigs running last fall and we have got 55 contracted now.

Andrew Coleman – UBS

No, I am sorry; I was just curious how many were working on your individual E&P segment?

Brad Guidry

Andrew we got a, I think it was 15, we were planning to be at 17 by late November was the plan that we were talking about in the summer, right now we are running at 3.

Andrew Coleman – UBS

At 3, okay and so do you have a goal in terms of where that might be to get by year end, I mean are they showing kind of a flat production, I mean are three rigs enough rigs to kind of maintain that flat production.

Brad Guidry

The plan right now is, as Larry mentioned, is to start the year slow. We will probably only run three rigs here certainly through the first quarter and well into the second quarter and see where things are. We have our inventory position, we think we can ramp back up quickly but we really do think the margins for drilling would be better in the second half of this year. So where that will go to in the second half, I am not really sure but for the first half I think you will see we will be somewhere around that three to four rigs operating for us.

Andrew Coleman – UBS

Okay so now everybody looks at phasing the production in, is it fair to see a little bit of decline here in the first half of the year and a little bit of perhaps some increase during the back to kind of keep it flat for the year.

Brad Guidry

Yes kind of the way the production will work is we were so busy last year drilling wells that we are still bringing on wells today that were drilled last year as the Haynesville Well I was mentioning and there are quite a few others. So I think our first quarter reduction will be strong and then second quarter you will start seeing the effects of only running three rigs and then it just depends when we get back to drilling.

Andrew Coleman – UBS

Okay great. Then I did not feel flipping through the reserve disclosure from a couple of weeks ago, I just want to make sure I didn’t miss it but is there a standardized measure or can you give any color on what is your standardized measure or PV10 were, I mean I am guessing the standardized measurement was about $800 million.

Larry Pinkston

I don’t have that with me but that is pretty close on a PV10 basis.

David Merrill

PV10 for 2008 for all our group was just under $900 million.

Andrew Coleman – UBS

So that will just be on the pretax basis and I will look in for the post-tax when you guys put the K out.

David Merrill

Correct.

Andrew Coleman – UBS

Thank you. And then incorporating the ceiling test impairment, what you guys think DD&A might go to, do you think there might just be a small decrease here for 2009 or do you think it will be bigger?

David Merrill

On the go-forward on the DD&A rate you will see around a 20% reduction from our fourth quarter rate. We were right at $2.65 for the fourth quarter we should be around $2.15 for the first quarter and that will be the starting point till the next measurement date.

Andrew Coleman – UBS

Absolutely, thank you very much.

David Merrill

You bet Andrew.

Operator

Your next question comes from the line of (inaudible) your line is open.

Unidentified Speaker

Thanks for doing the call. Can you give us a little bit better clarification on what you think your rig margins will be in the first quarter versus the fourth quarter, you mentioned overall rates may go down 4000, I tell you I am not sure quarter to quarter how that could translate in the margins?

Larry Pinkston

I don’t think the margins will be down quite. The 4000 a day was on the spot rigs that are just contracted basically well to well. We still have 12 or 14 rigs under long-term contracts that you don’t adjust well to well. So they will keep the average day rate up for the fleet and what the spot contract is but the margins are going to be ballpark-ish, $2000 to $3000 to $3500 to $2000 a day last from where they were in the fourth quarter and that is just a guess.

Unidentified Speaker

2000 and 3500?

Larry Pinkston

Again that is just a guess at this point.

Unidentified Speaker

Have you had anybody who tried to terminate any of your rigs that are under longer term contracts?

Larry Pinkston

Yes, I mean some of them that we had ordered rigs for we went to them early on to make sure that we were not going to spend another $10 million on the rigs and then when the rig was available to them they are going to tell us, we don’t want to rig and we are going to pay you off and we have had three rigs that we will be receiving penalty installation payments for this year, the other rigs thus far for the term contracts.

Unidentified Speaker

Okay. One of the questions in this environment, can you talk about your acquisition strategy for rigs or for your oil and gas producing properties as we look at 2009?

Larry Pinkston

I think there is going to be lots of opportunities this summer for oil and gas operation, acquisition and mid-stream operations. I am not as bullish on the rig operations side right now but I think in the mid-stream and oil and gas it is going to be lots. So everybody is going through barring based redeterminations here in the early second quarter and you don’t have a new number to go by and I think there is going to be a lot of properties on the market and as long as there is capital out there to buy them I think we are in pretty good shape for that. I think there will be some great opportunities.

Unidentified Speaker

So you are in a good enough – so you feel comfortable with your financial position or you could take advantage of that opportunity as they come up?

Larry Pinkston

Right and that is the other reason why we are starting off on a very slow side on our E&P operations is, you know, if those product acquisition opportunities open up during the year and we have not already stepped the majority of our E&P budget that we can redirect some of it towards the acquisition versus drilling oils.

Unidentified Speaker

Okay. One other quick question, which areas have you seen the most rigs laid down for your company, has it been in the mid-continent or has it been more on the Rockies or is it kind of evenly split between the two?

Larry Pinkston

The biggest impact to us of course is the mid-continent area and with rigs going down there. The predominant reason is that Oklahoma has been impacted a little heavier than other downturns is because of the differential we experienced in the fourth quarter, never before has mid comp areas have seen those kinds of differentials, I think a lot of that will be alleviated once rigs gets the second leg finished and then once the MEP and the other pipeline opens up going to Eastern Texas and Southeastern Oklahoma which is scheduled for a couple of months and then the other one in midsummer. So I am not as concerned about the differentials as it was last year but the differentials have been the biggest impact that we have never seen in this market before.

Unidentified Speaker

Okay and thanks for your comments.

Operator

At this time, we have no questions in queue.

Larry Pinkston

Let me just kind of summarize, we don’t know when the oil and gas industry will bottom out or when the US economy will return. We are focused on making the necessary adjustments during these very volatile times. This industry has always been cyclical and always will be. In any cycle there are always opportunities, our goal is to foster Unit Corporation in a very best position to take advantage of these opportunities as they present themselves. The things that make this possible at Unit are a combination of our strong balance sheet and our employee base both have the experience and the expertise to direct through these turbulent times. Thank you for joining us this morning and we hope to see many of you in the near future. Thanks.

Operator

This concludes today’s conference call, you may now disconnect.

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Source: Unit Corporation Q4 2008 Earnings Call Transcript
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