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Comstock Resources Inc. (NYSE:CRK)

Q4 2008 Earnings Call

February 10, 2009; 9:30 am CT

Executives

Jay Allison - Chairman, President & Chief Executive Officer

Roland Burns - Senior Vice President & Chief Financial Officer

Mack Good - Chief Operating Officer

Analysts

Kim Pacanovsky - Collins Stewart

Ray Deacon - Richard Capital

Ronald Mills - Johnson Rice

Jack Aydin - Keybanc Capital Markets

Dan McSpirit - BMO Capital Markets

Sven Del Pozzo - C.K. Cooper & Company

Rehan Rashid - Friedman, Billings, Ramsey & Co.

Operator

Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2008 Comstock Resources Earnings Conference Call. My name is Emanuel, and I will be your operator for today. At this time, all participants are in a listen-only mode. We will conduct a question-and-answer session towards the end of this conference. (Operator instructions) As a reminder, this conference is being recorded for replay purposes.

I would now like to turn call over to your host for today. Mr. Jay Allison, President and Chief Executive Officer. Please proceed, Sir.

Jay Allison

Emanuel, thank you for introducing me and welcome everyone. I think we probably should have a record crowd today and we will give you all the reports that we have and they are current for South Texas, East Texas, the Haynesville and every thing. So it should be an excellent meeting.

Welcome to the Comstock Resources fourth quarter and annual 2008 financial and operating results conference call. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com, and clicking Presentations. There you will find a presentation entitled Fourth Quarter and Annual 2008 Results.

I am Jay Allison, President of Comstock. And with me this morning is Roland Burns, our Chief Financial Officer; and Mack Good, our Chief Operating Officer. During this call, we will review our 2008 fourth quarter and annual financial and operating results as well as the results of our 2008 drilling program.

Our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct.

If you would go to the 2008 highlights, its on page 2 of the presentation, we summarize some of the many highlights in 2008. 2008 definitely was a transformational year for Comstock, which was recognized by the market as Comstock’s share price increased 39% for the year and was the number one performer in the sector.

For 2008, we reported revenues of $564 million and we generated EBITDAX of $459 million in operating cash flow, $438 million or $9.64 per share. We generated a record setting profit in 2008 of $252 million or $5.53 per share while many of our peers reported massive losses arising from write offs. Included in the record setting profit or gains from the sale of Bois d’Arc Energy and our sale of non-core properties, excluding these items and the discontinued operations, we reported reoccurring net income of $1.47 million or $3.25 per share.

The strong financial results in 2008 were driven by 32 % production growth and strong oil and natural gas process and the first three quarters of the year. The production growth is primarily coming from our successful drilling activities in 2008, 132; the 136 total wells that we drilled were successful. We had funded our $426 million in capital expenditures exclusively out of operating cash flow in 2008; this activity added 102 Bcfe to our proved reserve base, $116 million of our expenditures have been invested to increase our lease hold in the emerging Haynesville shale play.

Our proved reserves were negatively impacted by the fall in oil and gas prices, which cause 52 Bcfe in downward revisions, exploiting the downward revisions in the spending on backward leases in the Haynesville shale; we had a finding cost of $3.03 per Mcfe in 2008.

In hindsight, our best move this year was to complete the divestiture of our off-shore operations and $138 million in non-core properties prior to the onset of two hurricanes, the substantial decline in oil and gas prices, and the current credit crisis that we are experiencing. We are now positioned with a very strong balance sheet that will allow us to develop and prove up our Haynesville shale acreage this year.

I will turn it over to Roland to review the financial results in more detail. Roland?

Roland Burns

Thanks, Jay. Strong production growth is one of the major factors contributing to our record financial results in 2008, as shown on slide three in the presentation.

In the fourth quarter, our production averaged 164 million cubic feet of natural gas equivalent per day, 23% higher than our production in the fourth quarter of 2007 of 133 million a day. For all of 2008, our production of 59.9 Bcfe was 32% higher than production in 2007; pro forma production excluding the properties we sold was 58.2 Bcfe, a 40% increase over pro forma production in 2007.

Our East Texas/North Louisiana region averaged 91 million per day in the fourth quarter, which is 34% higher than the fourth quarter of last year. Production in South Texas was up 56% to 56 million per day, as compared to 36 million in 2007. The production in our other regions was 17 million a day down slightly from the 19 million a day, we averaged in 2007 fourth quarter.

Production growth slowed in the fourth quarter, as we are transitioning into drilling horizontal Haynesville wells and away from drilling conventional Cotton Valley wells, which have provided much of the production growth than we had in the prior quarters.

The Haynesville wells take much longer to drill and complete. Given this fact, we expect production in 2009 to fall in a range of 62 to 67 Bcfe or 7% to 15% higher than pro former production in 2008. Production is expected to be flat in the first quarter this year with production growth resuming in the second quarter when our recent discoveries in South Texas and in the Haynesville wells began to make a contribution to our production rate.

The fourth quarter saw rapid decline in oil prices. As we cover on slide four in the presentation, our average oil price decreased 31% in the fourth quarter of 2008. The $52.16 per barrel as compared to $76.10 per barrel in the fourth quarter of 2007.

Our oil price in the fourth quarter averaged 89% of the average NYMEX WTI price in the quarter, which was consistent with our average realizations last year.

For all of 2008, our realized oil price was $87.15 and was 43% higher than our oil prices $62.96 in 2007. Our average 2008 oil price was 88%of the average NYMEX WTI price. Slide five shows our average gas price, which has also declined significantly in the fourth quarter. Our average gas price decreased 10% in the fourth quarter to $6.44 per Mcfe as compared to $7.15 in the fourth quarter of 2007.

Our realized gas price was only 93% of the average Henry Hub NYMEX price for the fourth quarter reflecting the wide differentials that began in September after the hurricanes and also in combination with weaker natural gas liquids prices. We did have 11% of our gas production hedged in the fourth quarter, which increased our realized gas price in the quarter by $0.19 per Mcf. For all of 2008, our average gas price increased 28% to $8.83 per Mcf as compared to $6.89 in 2007. Our realized gas price was 98% as the average Henry Hub NYMEX price in 2008.

In going forward into 2009, we’ll have approximately 10% of our gas production hedged at $8.20 per Mcf. On slide six, we outlined our oil and gas sales, our sales from our continuing onshore operations increased 5% to a $100 million in the fourth quarter as the higher production level offset the declining oil and gas prices. For all of 2008, our oil and gas sales increased 78% to $564 million as compared to $332 million for 2007. The increased sale relates to the 32% higher production level we had combined with strong oil and gas prices.

Our earnings for interest taxes, depreciation, amortization and exploration expense and other non-cash expenses or EBITDAX from our continuing onshore operations was comparable to 2007’s fourth quarter EBITDAX at $72 million as shown on slide seven. For the full year 2008, our EBITDAX increased 83% to $459 million as compared to $251 million in 2007.

Slide eight covers our operating cash flow. Our cash flow just from our continuing onshore operations increased 26% in the fourth quarter to $80 million as compared to cash flow of $63 million in 2007’s fourth quarter. Operating cash flow in the fourth quarter of 2008 benefited from a reduction in our current income tax provision which resulted for the lower income we had in the quarter plus the ability that we had to use carry forwards and expense more intangible drilling costs due to the very large gain that we recognized on the sale of Bois d’Arc which is reflected in discontinued operations. For the full year 2008, our operating cash flow is $438 million, a 103% higher than cash flow in 2007 up $216 million.

On slide nine, we outline our earnings. We reported a net income of $252 million or $5.53 per diluted share for 2008, which is by far the highest annual profit at our corporate history. If you exclude the gains recognized from the sale of Bois d’Arc and the other properties that we sold in 2008 and the discontinued operations of Bois d’Arc and the impairments that we reported in the fourth quarter, we reported recurring net income of $148 million or $3.25 per share for 2008.

For the fourth quarter, we reported a loss of $96 million, which is caused by an impairment charge reported to reduce the carrying value of our investment in Stone Energy from $40 per share where we valued at closing in August to $19.19 per share where we valued at the end of the year.

Excluding the impairments taken in the fourth quarter our net income would have been $10 million or $0.22 per share. We outline our cost structure on the slide 10. Our lifting cost from the fourth quarter averaged $1.37 per Mcfe produced as compared to a $1.32 in the fourth quarter of 2007.

The decrease in the proved reserve base that we had at the end of 2008 resulting from the lower oil and gas prices has increased our DD&A rate to $3.33 per Mcfe in the fourth quarter of 2008 as compared to $2.81 in 2007’s fourth quarter.

In slide 11, we outlined our production cost for full year. Our Lifting cost averaged $1.45 per Mcfe in 2008 up slightly from the $1.43 we averaged in 2007. Our DD&A per Mcfe produce increased to $3.03 per Mcfe in 2008, as compared to $2.76 per Mcfe in 2007.

On slide 12, we outline our capital structure at the end of 2008. We had $210 million in total debt at the end of the year. In the fourth quarter, we borrowed $35 million under our [buying] credit facility, which has a $590 million borrowing base. We borrow these funds in the substantial cash balances we own on hand mainly to make the tax payment that was due from the gain on Bois d’Arc that was due on December 15th.

We ended the year with equity of about $1.1 billion. So our percentage of debt to our total book capitalization was at 17% at end of the year, which was a substantial improvement from the 50% level where we stood at the end of 2007.

We ended the year 2008 with a very strong balance sheet and the company is now very well positioned in this period of tight credit with $555 million undrawn on the credit facility.

On slide 13, we detail our drilling expenditures for 2008. We spend $426 million in 2008, for our drilling program as compared to $325 million that was been in 2007. $333 million of the dollars were spent on our East Texas/North Louisiana region. $85 million was in South Texas and $8 million was spent on other regions. $116 million of the $426 million spend was fed to acquire unevaluated lease hold in the Haynesville shale play.

I will now turn it back over to Jay.

Jay Allison

We’ve got several more slides and then we’ll open it up for question and answer. If we got to slide 14, we have a slide on our proved reserves on page 14 of the presentation. Our proved reserves at the end of 2008 were estimated at 582 Bcfe compared to the 651 Bcfe reserves related to our continuing operations at the end of 2007.

Our reserves were 90% natural gas and 67% of proved develop and we operate 85% of the proved reserve base. The present value using a 10% discounted rate of the future net cash flow before income taxes of the reserves at the end of 2008 is approximately $820 million using year-end December 31, 2008, oil and natural gas prices of $34.49 per barrel for oil and $5.33 per Mcfe for natural gas.

We produced 60 Bcfe reserves in 2008 and the best of the 59 Bcfe in 2008, of proved reserves relating to certain non-core properties. The proved reserves were negatively impacted by downward revisions of 52 Bcfe. These revisions were primarily the result of the lower crude oil and natural gas prices used, at December 31, 2008, to determine whether the production or development of future reserves would be economic.

Using 12-month average process as of the first day of each month for crude oil and natural gas prices realized by the company in 2008 of $78.09 per barrel and $8.32 per Mcf. Our proved reserves would increase to 617 Bcfe with the PV 10 Value of $1.8 billion.

We spend $426 million in 2008, on onshore acquisitions, exploration and development activities, which added 102 Bcfe to our proved reserve base resulting in finding cost to$4.16 per Mcfe if you exclude the downward revisions. If you exclude the $116 million that we spend on unevaluated leases in 2008, the finding cost improves to $3.03.

On slide 15, we focus on our East Texas/North Louisiana region. We drilled 115 wells in this region in 12 different fields in 2008, all but one of these were successful, 10 of these wells were horizontal wells, we have tested these wells at a per well rate that averaged 2.8 million cubic feet equivalent per day, a substantial improvement from our average rate in 2007, a 1.4 million cubic feet equivalent per day. The prolific wells at Hico Knowles and Terryville Cotton Valley in Haynesville horizontal wells account for the improved per well results.

The horizontal wells averaged 8 million cubic feet equivalent per day and the vertical wells average 2.4 million cubic feet equivalent per day, many of the vertical wells were drilled in the Logansport in Hico Knowles, Terryville area in North Louisiana.

We drilled 37 wells in the Hico Knowles, Terryville area. All of these wells have been completed and had initial production rates which averaged 3.5 million cubic feet equivalent per day. We drill 45 wells at Logansport field, 41 of these wells have been completed with initial production rates which averaged 2.1 million cubic feet equivalent per day. If you would turn to the Haynesville shale play slide which is slide 16, we outlined our holding in the emerging Haynesville shale play in North Louisiana and East Texas.

Our acreage is highlighted in green. We currently have 86,032 gross acres and 70,504 net acres that we believe are perspective for Haynesville development. Given expected well Spacing of 80 acres and an expected well recovery rate of 5 Bcfe per well. Our acreage could have 3.3 Tcfe of reserve potential. We have two producing horizontal wells and are in the process of completing three more.

I will have Mack Good our Chief Operating Officer go over these wells. Mack?

Mack Good

Thanks Jay. Has everyone can see on slide 17 we have a map showing our current activity in the emerging Haynesville shale play. We have completed two horizontal wells and have eight additional Haynesville wells in progress. The BSMC# 7-1H well in the Toledo Bend North field was successfully completed in December of last year with an initial production rate of approximately $9 million a day. We have an 88% working interest in this well. We have a 22% interest in El Paso’s successful Gamble 24# 1H which was recently completed with an initial production rate approaching 14 million a day.

We are currently completing three additional Haynesville horizontal wells. We operate all those wells. Our second operated Horizontal Haynesville wells is the Collins#15-1H in the Logansport field. This well was drilled to a total depth of approximately 11,350 feet and has a 42,000 foot lateral. This wells completion has been delayed due to mechanical problems. We are completing the Bogue A #6 well in the Waskom field. This well reached an 11,400 foot vertical depth with a targeted 4000 foot lateral extension. We are also completing the Hart#1H in the Logansport field which reached 11,500 foot vertical depth and it has a 4000 foot horizontal lateral.

We have five Haynesville horizontal wells drilling. The Green#13H in the Blocker field has reached an approximate vertical depth of 11,650 feet and we are currently drilling ahead, this wells horizontal 37,000 foot lateral. The Headrick #1H in Bethany-Longstreet field has reached a vertical depth of 11,850 feet and we are currently drilling the 4000 foot lateral on this work.

The Holmes#1H in Logansport is currently drilling at a vertical depth of approximately 11,000 feet and will drill a few hundred more feet and kept well off and drill an approximate 4000 foot lateral on that well. We’re also drilling in Moneyham#7H in Longwood field and this well is currently drilling at a vertical depth approaching 11,000 feet.

We also just finished drilling the vertical section to 11,730 feet in the BSMC LA#12H well in the Toledo Bend, North field and this well is waiting on the spot of its horizontal section.

Now I’ll turn it back to Jay.

Jay Allison

I am sure in a moment that you all will questions will be addressed to Mack on the slide 17, and we’ll pull this back and go over again in a moment. I would like to continue the presentation and go to tab 18. Our South Texas region is displayed on slide 18. In our South Texas region, we drilled 15 successful wells in 2008 and we had three dry holes, 14 of these wells have been tested at per well on an average rate of 4.3 million cubic feet equivalent per day. Four of the successful wells were in the Las Hermanitas field in Duval County, Texas, six were in the Javelina Field in Hidalgo County and three were in the Ball Ranch field, and one was in the Lorenz Ranch field. The most significant discovery in this region of course is the Leyendecker #10 well drilled in the Fandango field.

On slide 19, we have a map of our Fandango field. We are currently completing the Leyendecker #10 well in Fandango field. We have a 100% interest in this 16,200 foot well. And are currently finishing this wells’ multiple stage completion. We have two wells offsetting this successful exploration well. We are currently drilling the Trevino#3 to a plan vertical depth of 14,900 feet. And recently drilled the Muzza#13 to a 16,300 foot vertical depth. Both of these wells appeared have encountered the targeted Wilcox sands and are expected to be successful. We have some more comments on those in a moment.

If you return to the 2009 drilling program which is tab 20. We announced today that we are reducing the 2009 capital budget from $450 million to $366 million in response to weak natural gas prices. The revised budget, which is outlined on slide 20 as comp stock drilling approximately 41 wells this year are 34.8 net wells. The drilling program will continue to be focused on our higher return opportunities including our extensive acreage position in the Haynesville shale.

The East Texas/North Louisiana operating region accounts for the largest portion of the revised 2009 budget with forecasted expenditures of $319 million. We now plan to drill 36 wells in this region or 31.4 net wells in 2009, which includes 30 Haynesville shale horizontal wells or 25.8 net Haynesville shale wells and two Cotton Valley horizontal wells. And we expect to spend $47 million in our South Texas region to drill 5 wells in 2009.

On slide 21, we display what we plan to drill the 30 horizontal Haynesville wells and this is important, we expect to have an average of 86% working interest in these wells, we plan to drill these wells with the goal of proving up as much of our acreage as possible instead of just drill in one area to maximize current production. We think this program has potential to provide us with substantial reserve growth in 2009.

On the 2009 outlook, which is slide 22 and looking ahead to this current year, we feel that Comstock is very well positioned to continue to grow and add value to our stock holders even in the challenging environment that we all live in now. The divestures of our stake in Bois d’Arc Energy and the non-core properties that we completed provided us an extremely strong balance sheet, which will allow us to aggressively support the continued growth of our onshore operations, which is increasingly important given the tight credit market that we are in today.

We are well positioned for future growth with a large inventory of drilling locations in the Cotton Valley and in the Haynesville shale in East Texas and North Louisiana and in the Vicksburg and Wilcox trend in South Texas. We reduced our drilling program to $366 million in order to maintain our financial flexibility.

We plan on only drilling our highest return projects this year, which primarily focuses on the Haynesville shale. Our primary goal in 2009, is to prove up a portion of the 3.3 Tcfe reserve potential that are positioned in the emerging Haynesville shale play exposes us to. I would like to now turn it back over to Emmanuel. And we will open it up for questions.

Question-And-Answer Session

Operator

(Operator instructions) And our first question will come from the line of Kim Pacanovsky - Collins Stewart.

Kim Pacanovsky – Collins Stewart

Could you give us some details on the El Paso wells, the number of stages, the choke etc?

Mack Good

Sure Kim. This is Mack, the well was drilled to 16,100 foot measured depth with an approximate 4000 foot lateral. It was stimulated in 10 separate stages and it flowed 14 million a day with a little over 4000 pounds flowing casing pressure on initial test and our report is of yesterday it’s continuing to flow at plus $8 million a day rate.

Kim Pacanovsky – Collins Stewart

Okay. And you just have a tiny bit of acreage in that region is that correct?

Mack Good

Actually no.

Kim Pacanovsky – Collins Stewart

Okay that’s in Bethany-Longstreet. What you are acreage there?

Mack Good

In Bethany-Longstreet, we have at least three sections of Haynesville.

Kim Pacanovsky – Collins Stewart

And what is your total acreage at Logansport and also your total acreage just in De Soto, Parish,

Mack Good

De Soto, Parish were over 30,000 net acres well over 30,000 and Logansport it’s probably around 3000 acres Kim.

Kim Pacanovsky – Collins Stewart

Am I correct that your well, the Collins well in Logansport will be the first completion in that field in the Haynesville?

Mack Good

Yes. On a horizontal well

Kim Pacanovsky – Collins Stewart

Yes, okay great. And the two well in the budget for South Texas are they the two wells at Leyendecker that are drilling now, will those wells spud after year-end?

Mack Good

It is the Muzza#13 and the Trevino#3 they were spud late in ‘08 and early ‘09 and so it’s carry over money for those wells and we also have a couple of wells in the budget for our assets in Kennedy County.

Kim Pacanovsky – Collins Stewart

Okay. And a couple of questions on the numbers. Thank you Mack. Roland how do you determine the amount of interest you will capitalize and what should we expect, what should we be considering in our models going forward for ’09?

Roland Burns

The interest that we have on our unevaluated properties and so even though we have always capitalized, but that’s not been a very significant amount in the past, so that was been noticed, but since then this quarter, we have fairly large balance in the unevaluated properties, which is mainly all the Haynesville leases. And we had such low interest expense and obviously it’s a much bigger component. So, it would be as simple, we capitalized $1.7 million in the fourth quarter in interest and it probably would be a similar number in the next couple of quarters until we evaluate that acreage and move that into properties.

Kim Pacanovsky – Collins Stewart

Okay. I don’t have an accounting background, this maybe a dumb question. But are you forced to capitalize that or is it your choice to capitalize it?

Roland Burns

Whenever you have something that is unevaluated and it is active, you capitalize interest. We have always capitalized interest on it. It just hasn’t --

Kim Pacanovsky – Collins Stewart

It just was so small, because I saw in 2007 you really didn’t have anything capitalized.

Roland Burns

We had so little acreage.

Kim Pacanovsky – Collins Stewart

And a little bit in ‘08, okay. All right, and just a question on the differentials, I mean I don’t know if you are projecting going forward, they still sink right now. What are you looking at for the future and is there any thought on hedging basis differentials or does that go into your anti hedging policy?

Roland Burns

When we do hedges, we always do hedges with the basis. That’s not going to be a hedge. So the hedge that we have is basically a Houston ship channel for that South Texas gas, because that causes them, where that gas is sold. Well, it’s hedge basis, when we do a hedge. But as far as, I think what’s happened is the different market, the different trading hubs, there is less liquidity that’s available in those areas and so that’s also partly contributing to the water differentials, the lack of liquidity in those different trading hubs compared to what we had in the past.

Kim Pacanovsky – Collins Stewart

But in East Texas, I mean, do you expect that differential to widen as a lot of this Haynesville production comes online and there is obviously the local demand with industrial demand being down so much these days. So do you think it’s going to get worse before it gets better on the differentials?

Roland Burns

It actually improved about late December, we saw Houston ship channel tighten up. So, it’s really, it’s hard to project what will happen in different regions, but I think obviously the transportation cost in North Louisiana will be higher as it’s more competitive to get into the different markets and some times that cost we reflect in lifting cost, some times it’s in the differential dependent on kind of where the title on the gas is taken.

Kim Pacanovsky – Collins Stewart

Okay. And Mack have you had any mechanical issues on the Bouge well or what is it, the Hart that’s been completed now?

Mack Good

No, we have had no issues on either of those wells.

Kim Pacanovsky – Collins Stewart

Okay. And when do you guys, what’s the current situation now with the Collins well and when might we expect you guys to say something about these three wells that are completed?

Mack Good

Well, the Collins well, the mechanical issues were caused by failures of surface equipment during a frank job and we had to make several repairs to the well bore integrity. And now we’re cleaning out the well bore, there is an obstruction that we’re trying to remove and so in a few, I will guess 2 to 3 weeks, we should have the well hopefully back to a status where we can complete the well bore and with regards to the other two wells of the Bogue is about three-fourths complete. We have a couple of stages to go and the Hart, we are just rigging up for the first stage on that one.

Kim Pacanovsky – Collins Stewart

Okay. All right, so it’s going to be a little while. I had one more question and then I will leave it to someone else. Any plans to do a mid-year reserve report this year being that you are going to have all of this Haynesville activity.

Mack Good

We have an internal review every quarter here at Comstock and we’re certainly going to go through that process and have that for internal assessment.

Kim Pacanovsky – Collins Stewart

Okay. But no outside report?

Mack Good

Hadn’t planned one.

Operator

And our next question will come from the line of Ray Deacon - Richard capital.

Ray Deacon - Richard Capital

Hi. I guess a question for Mack. What do you think about the Comstock announcement on transportation and does that allow you to kind of breathe a sigh of relief and may be one other question about proponent and what you expect to use resin coated or ceramic proponent, and what seems to be working and then just a last real quick one, based on the two wells you’ve got, do you have enough data to still feel confident about 5 Bcfe per Haynesville horizontal.

Mack Good

Could I get a little clarification on the transportation?

Ray Deacon - Richard Capital

The Chesapeake announcement that they are going to be building large increase of take away capacity of I think they announced 1.2 Bcf a day. I guess in any of the areas you are in, I guess do you see any bottlenecks and how are you handling that and I guess?

Mack Good

We are pleased by any improvement when we hear of any improvement in the take away capacity in the Haynesville for obvious reasons. The VP of Marketing here at Comstock has been working diligently on acquiring the firm capacity that we think we will need. We have some relationships that I can’t give you details on, but we feel comfortable in the relationships that we have that we think will be able to provide the firm as we build right.

With regard to the profit question that you had, we have been keeping very close tabs on what other operators are doing with not just the proponent selection, but the types of jobs that are being pumped. We’re sharing data with various other operators and we are certainly very interested in the resin coated selection on the proponent. And we think that can yield some real dividends especially in cost savings that’s for sure. And Ray what was your third question?

Ray Deacon-Richard Capital

It sounds like you are still pretty confident about the 5 Bcf number?

Mack Good

Absolutely, we feel very comfortable that our tight curve is strongly supported all the data we have and as you know, we have been fairly conservative throughout this forecast in forecasting the Haynesville and we think as the data accumulates that perhaps we can move that tight curve north, but right now we are staying with our five because we think that’s a conservative estimate.

Jay Allison

What we did Ray if you go back several things, if you read the, everybody says the Wall Street Journal, I mean you look at front page of Wall Street Journal and the highlights are I was young, I was stupid, I was naïve and I think that can apply to the energy business too. I think what we try to do in giving you that 5 Bcfe, I mean we learned 10 years ago when we bought Bois d’Arc in ‘07 when oil went from $35 to $9 in April this was in ‘97, in ‘98 oil went from $35 down to $10 a barrel then we didn’t have long-term debt, we had all kinds of problems and we learned this cycle and we needed to divest ourselves with a bunch of things and we learned that 10 years ago, we also learned that when we ramped up the Cotton Valley program that to drill 50 wells or 100 wells was almost impossible to do with the man power that we had.

So, we have tried to be conservative on the numbers that we’ve given out. Now we missed few of them, but we initially came out with like 4 Bcfe and then as of December really January this year, we said well, we think its 5 Bcfe and I know we did marketing trip on the East coast, the second week of January so and people would say why are you comfortable with 5 Bcfe now as you are, we said well, there is a lot of additional data out there and we believe it and we have our own data.

So, when we give you those numbers we hopefully we’re on the bottom end of aggressiveness and we’re accurate. So, hopefully we will move that number from 5 to 6 Bcfe people, but we are not there yet.

Operator

Our next question will come from the line of Ron Mills - Johnson Rice.

Ronald Mills - Johnson Rice

A couple of questions. Mack, can you give us a little bit of an update on the BCMC number 7 the first well you brought on in December. I think you walked through where the gamble is currently just curious as to how the BSMC 7 had been moving up?

Mack Good

Sure. The first 30 days averaged north of 6 million a day. That’s above our 5 Bcf tight curves. so we are quite pleased with the profile, it’s continuing to produce a little more than 5 million a day, the pressure decline has stabilized and is sitting there making 5 million a day and has for the last 2 to 3 weeks. So, we are very pleased with the wells performance.

Ronald Mills - Johnson Rice

And just I guess follow-up a little bit on one on Kim’s questions at least where I think she was going. From pricing situation in East Texas and North Louisiana, what’s the best pricing point to look at, I know a lot of people particularly on the East, looking towards Perryville, but I know there are back hall options to cart this. Going forward, whether it’s for you Mack or may be a marketing guy, what should we expect to look forward in terms of a pricing hub?

Mack Good

Well, I personally like all the options. I wouldn’t take anything off the table as far as moving the gas out of the Haynesville and certainly all of the operators that have substantial acreage positions and a reasonable drilling program this year, would agree. And so, we want that additional capacity and as a previous individual mentioned, Chesapeake has announced that they are installing some additional capacity, there is a couple of other rumored installations again that we have had some conversations with some folks about. And as all the operators are doing, we are looking at laying our own pipes to facilitate the transport of our gas. So, back to your original question, I would certainly keep all the options on the table.

Ronald Mills - Johnson Rice & Company

And in addition to that energy transfer line, Chesapeake is the lead supplier in known regencies; they are now talking about there, Haynesville lines, have you all locked up any from of transport at this time?

Mack Good

We do, we do have some firm locked up, yes sir. And at this time, we think it’s sufficient for the near-term.

Ronald Mills - Johnson Rice & Company

In this near term 2009 or?

Mack Good

Yes, that’s our intention.

Ronald Mills - Johnson Rice & Company

Okay and then lastly in South Texas, it sounds like both the Muzza and the Trevino have encountered pay, obviously the Trevino is not being drilled as deep, should we take that to mean that it’s not necessarily targeting the same three zones that the Leyendecker encountered and is the Muzza also targeting that three zones. I’m just trying to get a lay of what to look for?

Mack Good

Sure. The Muzza has been logged and we will complete that well in the near-term, the Trevino, we are continuing to drill the well to improve our structural position and those two wells did hit some of the same reservoirs as the Leyendecker and we are quite pleased so far with what we have seen.

Ronald Mills - Johnson Rice & Company

And then the status of the Leyendecker?

Jay Allison

The Leyendecker is being completed as you would certainly expect from the bottom up, we have had a couple of test zones that we wanted to evaluate for obvious reasons; it bears on future work in the field. So, the completion is taking longer than it would otherwise, we are currently at the top of what we call the T6 Wilcox reservoir and we are evaluating that zone and we hope to frac that zone some time next week.

Ronald Mills - Johnson Rice & Company

And, was that expected to be the initial producer or?

Jay Allison

We’ll probably mingle that zone with another package of reservoir sands up the hole? So it will probably be another three to four weeks before we get the well buckled up and flowing to sales.

Ronald Mills-Johnson Rice & Company

And how shortly after that would you expect to follow with the Muzza and the Trevino?

Mack Good

The Muzza is probably going to be right on the heels of the Leyendecker, the Trevino I am a little uncertain just because of the directional work that we are doing and getting a logistic schedule for that one. So I have to remain vague on the Trevino.

Jay Allison

Ron the other thing for you and Ray and Kim, if you look at reserve adds, which is a focus of ‘09. I mean the Muzza and the Trevino we didn’t add any reserves in ‘08 for those wells and as Mack said, we did encounter Wilcox Sand and we do expect the Leyendecker well to be a big well and Mack kind of gave you a timeframe on that.

Ronald Mills-Johnson Rice & Company

And I would assume you’ll weren’t able to book much on Leyendecker here and do you guys don’t have any production. Right?

Mack Good

Right.

Jay Allison

And I think even if you go to Haynesville. We book may be 10 Bcfe in all of the Haynesville, because when we had our well and then the El Paso well. So if you look at the future of ‘09 in reserve adds it hopefully will be substantial, because we didn’t book many Haynesville reserves in ‘08.

Ronald Mills-Johnson Rice & Company

I think people talked about booking a couple of spuds per producing more, were you able at least in the year, your biggest Mc 7 well to book a couple offsets?

Mack Good

Yes sir. That’s the only well we were able to evaluate and time do that with.

Joy Allison

That’s again its around 10 Bcfe and Haynesville so the beauty of ‘09 is it. Really in story is we’ve already ramped up the drilling program that should result in hopefully material reserve adds for the 30 Haynesville horizontal wells and then you can add the two Cotton Valley Taylor wells and then the wells that you are talking here, the two deeper Wilcox wells for South Texas. So, the gross should come with that, having to issue expense of equity or expense of senior notes, and we should be able to maintain our strong balance sheet to this down cycle and yet grow the reserve base; get the drill bit and again all this is possible, because in ‘08 we were just so fortunate to complete the divesture of our off shore properties and to sell the non-core assets and we did all that prior to the Hurricanes and decline in oil and gas prices and of course before the current credit crisis, they were in. So I don’t think we have ever been better positioned to grow than we are today and lot of that will be, the next three quarters reporting really from Mack on how we are doing in the Haynesville.

Ronald Mills - Johnson Rice & Company

And since you bought up the balance sheet and you avoided the acquisition market last year and built up your balance sheet? There has been a lot of questions about the A&D market out there given the credit volumes you just referenced. Have you all seen the A&D market, eat up a little bit or at least have an increased number of opportunities that your balance sheet can?

Mack Good

No, Ronald the way we look at that, our business model in ‘09 does not require anybody or anything or any material acquisition it’s a add to the Haynesville, we have been doing that on a monthly basis, it’s to figure out how to complete the Haynesville wells without being delayed a month or two, which we have been delayed. So, we have got to get over that learning curve, and we have said in all the meetings that we have had this year that we don’t see this credit crisis going away in a blink of an eye, it’s going to be here a little while. So, our $590 million availability, we have kind of put a marker in the sand and said we want to maintain at least half of that period. We would not want to use our credit line and have less than $300 or $350 million of availability left.

We want that amount unused. So, if we were to go out and find something we just fell in love with that we needed to own, we would not lever this company up. We would issue shares to do that and we are very stingy on that, I think the last time we issued that, it was maybe in ‘03 and even when the stock was $90 last year, we didn’t think the right thing to do was issue equity. We think you have to have two things, you have to have a healthy company, which we have and you have as a stock holder. But another thing, you have to grow this stock price for the share holders and typically you don’t do that by issuing a bunch of equity or incurring a lot of expensive debt, you do that by developing your core area and I think that’s that we hopefully, we will have 7% to 10% production increase this year, may be more.

We don’t know, we have got to see how the Haynesville performance. But, we could have some material reserves adds; that is our total goal this year is to keep 5 to 7 rigs running in the Haynesville, we will see where commodity prices end up and really, really grow the reserves, and I think that’s where Kim came in with that question at mid-year, would you do a reserve report well, I don’t know we typically never do. But, we do plan on adding some material reserves. I think that’s a great growth program for the market that we are in and no we have not seen any properties out there or companies that are worth buying. Those that are for sale, typically have a reason to be sold. We have avoided that.

Operator

And our next question will come from the line of Jack Aydin - Keybanc Capital Markets.

Jack Aydin – Keybanc Capital Markets

And most of the questions are answered. But, this is directed to Mack, Mack the Collins well, the Leyendecker well, they are both delayed, whose at fault, is there people, the service companies that you are using or what’s holding them up so much?

Mack Good

Well, I will take the Leyendecker first. The Leyendecker is delayed just simply because we encountered some sands at the bottom of the hole that we wanted to test in order to get some data that we thought would be important in the continued development of Fandango and so it’s no one’s fault, you can blame me, I made the decision to do that just because it’s in the best interest of everyone to get that information.

With regard to the Collins, what happened, the devil is always in the details, no matter what business you are in? But in the Collins completion, we had some surface equipment that as I mentioned earlier that failed during the frac operation and that particular piece of equipment is a equipment that is rented by every operator from vendors in the oil and gas industry that supply that sort of equipment and we have used this particular vendor many, many times. We never had a problem except for this particular instance and so certainly we are working with that vendor to ensure that this doesn’t happen again that the appropriate steps are taken to minimize the possibility of that occurrence.

We were thankful, very thankful that no one was hurt when that piece of equipment failed and you have to understand and I know that most of the listeners have not been on a job that involves a massive hydraulic fracturing operation especially in the Haynesville. But it’s very high pressured high rate work and safety is number one on jobs like that. So, we are taking the appropriate steps, but no, I wouldn’t say that it’s anyone’s fault things sometimes break in the real world as you know. So, we are taking the necessary steps, as I mentioned earlier to ensure that is not likely to ever happen again.

Roland Burns

But Jack you had heard that the last well is a dry hole, all that garbage. No, with a well ahead blow-off and nobody knew that what happen and then we had some fishing tools hung in the hole and we are fishing them out. So, did we disprove the Haynesville in that area no? We have had a problem on a well and it’s taken probably another 6 weeks longer than we thought or may be two months, that’s what you get for highlighting one well, that’s why we try not to do that. But I know, it’s counterpart of the dance right now, every well is important. But, we did have problems, we had problems on the first well that Toledo Bend, North well, we had five-stage frac, the service company moved off, they moved back. We have had the final five stages. We had a 9 million a day well, would it have been better to have 10 stages at one-time, absolutely, is that our goal, absolutely, is that why we have hired slumber jacks to do, absolutely.

So, I think again, if you just like at this momentum and if you look at the chart of the slide 17, we have tried to outline what we are doing, what is being told and we are going to be doing a lot more of the same thing with the same people. And hopefully, we will be a lot more predictable. Because believe me, we wanted to deliver the news of the Collins and the news of the Leyendecker, but it is kind of is what it is, you have to trust that we are going to better at it. And I think we will.

Jack Aydin- Keybanc Capital Markets

I’m sure you will. How much of reserve you booked from the Leyendecker?

Mack Good

We booked about 13 Bcfe net to our revenue interest for the Leyendecker discovery.

Jay Allison

It was pretty substantial this February.

Mack Good

Well, we told you we thought it is a really good well and that’s why we drilled a well to the north and south of it, which we are in two different soft blocks. So, that’s all, again the wells that we drilled this year is a 40 some odd wells. If they are successful, those will add new reserves. You won’t convert spuds into PDP, you will add new reserves and I think you add them in our core area and you add them with the people that have created the wealth of the company and you do it with a strong balance sheet and you keep your strong balance sheet and may be that’s where you come in, mid-year and you would have added a lot of reserves and your borrowing basis even better. But I don’t know, we are going keep all of our strength around this.

Jack Aydin- Keybanc Capital Markets

Back to Kim’s comment, would you elect to do some operational updates in the middle of the quarter since you have a couple of wells that are in the process of completing and fracing and everything, Jay?

Jay Allison

Jack it’s funny, I read everybody’s update, because I respect all the analysts, and I read one report from I won’t name is name Ron Mills and he said that in four to six weeks, we would may be give an update, you know Jack I think that if it’s so important that you know and we have a couple of wells that are completed, good are bad doesn’t matter, but we know they are absolutely completed and we are finished with them. And they are producing what they are going to produce either be the Leyendecker, the Collins are the Bogue.

Then what we normally do is Mack and Ron I will get together and we’ll see what kind of pressure we have from the outside world and then we will say okay. We try to do it on a quarterly basis, may be we don’t make it to the next quarter may be we have to do some thing in six weeks this time. And then try to get everybody to this quarterly basis. So I don’t know, you could probably bend our arm enough and we might do something, but we can’t have this Collins deal, it’s like an overhang forever and ever and ever.

We need to get systematic approached information, some of the other companies, Jack they are drilling and completing five and 10 wells at a time. And when you get to that stage then you are giving a lot of information out, I just hate to give it out on one or two wells all the time. But we are going to listen to everybody and we think it’s material then we have a duty to put something out.

Jack Aydin-Keybanc Capital Markets

Just to get rid of the Collins.

Jay Allison

We are going to be fair and do the right thing, if we don’t then slap us around.

Operator

And our next question will come from the line of Dan McSpirit - BMO Capital Markets.

Dan McSpirit – BMO Capital Markets

Of the Haynesville shale horizontals that you drilled in 2009, how many of those will test or verify 80-acre spacing?

Mack Good

That’s a good question. We’re drilling as you know a wide area as Jay mentioned earlier in the presentation. So I can’t give that to you Dan, I can get back to you on that. We are testing eight or nine different areas. So proving up the 80-acre spacing isn’t the initial goal.

Jay Allison

We can get back to you with that I mean, that is a great question, it’s eight different areas for the 30 wells again. It’s 30 gross wells, but it is almost 26 in that well, so it’s a lot of ownership in those wells.

Mack Good

Dan, you can see on the breakout I think its slide 20. You can see what we are drilling and certainly like in Logansport and Toledo Bend North, there might be some prove up, but and I know Toledo Bend North is about 20,000-acre package. So there is a lot of room there too.

Dan McSpirit - BMO Capital Markets

Yes, understand. And another question here, were the wells currently drilling and those that are planned throughout 2009, will they be completed any differently from what’s been done thus far and if so how?

Mack Good

Well, that’s another good question. And the short answer is yes, because we are changing already. And as I mentioned earlier, we are creating data with various other operators. The land grab part of the Haynesville play is over and now everyone has pretty much agreed to share information on a confidential basis and so we have several agreements in place to do that. And as a consequence, we’re all learning what not to do is as important as learning what to do. So, we certainly will change our frac designs up and our completion approach. Yes sir.

Jay Allison

And we are working Dan, well I will let Mack go, we are working with people that do it best.

Mack Good

We are working with several groups and since it’s confidential I’m not going to name names here. But we’ve learned a lot and I think they have too through the exchange of the data and as far as how we are changing, certainly there is a move towards going with certain proliferation phasing, certain clustering of the purse in order to properly fracture this targeted stage. We are filling up the fluids, we are changing the proponents; we are changing the concentrations that we are pumping. So there are a number of things that are being changed.

Dan McSpirit - BMO Capital Markets

Then lastly, your original budget of $450 million was announced at the beginning of January and so herein for short, we could see you’ve cut it by close to 20%, what price or prices in the future strip do you have to see to revisit that number of $450 million and if you did revisit that would it all go to the Haynesville?

Roland Burns

Yeah, Dan. this is Roland. I think really what because our original budget was set late December, at then announced early January, and we are looking at 2009, our top process was that gas would probably average in close to $7 an Mcf and I think, January it was six and then February, we suffered through a big drop off in gas and that is below $5 and I think getting below $5 was kind of a signal that $7 is way off the margin and we really wanted to go into our secondary, we call it “the squirts dirt budget” and that’s what we kind of put out here, which was the easy reduction for the dropped off activity that we mainly had planned for the second half of the year, when we are ramping up with seven rigs in the Haynesville.

We still really don’t have to make that decision until later in the year, as far as actually letting rigs go before we get new rigs in. but, it will be very easy for us to put the budget back to the higher number if gas prices improve. But given the outlook for gas has now in the very low February prices, we are going to realize. We thought it was best to go ahead and make that the target budget the lower budget. So --

Mack Good

But then we took the different areas Dan, we said in South Texas all that acreage has helped our production in the Fandango, the recompilations from 16000, 18000 feet, which we think we have a bunch of those debt reserves, I mean, that’s all behind pipe and we own a 100% of that. Any recompletions from 12,000 to 16,000 feet in some of the 20 Fandango wells we pushed that off, because again we don’t lose it. We did drill the well to the north and south, the Muzza and the Trevino.

We are going to produce those to the end of the second quarter, see what kind of decline curves we have, what kind of bottom hole pressure. And if we need to drill some more commodity prices go up and we can do that. But, we don’t lose acreage by not drilling those wells, same thing with the horizontal Cotton Valley, Taylor, the five that acreage has helped our productions. So, we don’t lose the acreage and the same way with the 18 vertical Cotton Valley wells, we said well we can push most of those of because we don’t lose acreage there. And we kind of did it in $50 million increments and we just kind of hunkered down and said what is it that we are really trying to do in ‘09 and do we have the services to drill the Haynesville wells and do we have the manpower, do we have expertise and then we kind of put up this whole chart, which is slide 17 it says okay.

We have put up the scorecard, here is the wells we are drilling and here is the ones we are completing and we are just going to keep adding on to that and we want to preserve our credit facility and I think that’s in the past ten years ago. We are very young stupid and naive and we thought we could get out of the credit crashes and stake and I don’t think any company can and we don’t want to get in that box, it’s in an ugly one. So, as we’ve said in January, we’ve got five rigs, now that have top drive, we used to drill horizontal Haynesville wells in the third quarter.

We will get two more rigs and they we have our domain rigs and we can elect then to either release two of our existing five top garb rigs and just keep a five-well program or we can have the seven-well program in the latter part of the third and fourth quarter for Haynesville as Roland said, we don’t really have to make that decision now. We did cut the budget back assuming that they will just have a five-rig program, but if we wanted to ramp it back up again, I think we could do that, we just don’t want to mislead you and how many wells that you will think we will drill now if we changed it.

Dan Mcspirit - BMO Capital Markets

Then one last question here, you booked 13 Bs on the Leyendecker. What’s the final estimated drillings complete cost for that well?

Mack Good

It’s probably going to be around $14 million.

Operator

And our next question will come from the line of Sven Del Pozzo - C.K. Cooper & Company.

Sven Del Pozzo - C.K. Cooper & Company

My questions relate to cost for the most part, I would like to know whether you could decompose the operating expense of $1.37 per Mcfe experienced in the fourth quarter to break out the production tax component just so I can get a better feel for where your controllable lifting costs are trending.

Roland Burns

Production taxes were only 1.8 million of the total 20.6 million in the fourth quarter. But they have come down a bunch, part of that was just to the lower prices, but also we have a bunch of properties qualify for some reimbursements for tight gas kind of severance tax reimbursements.

Sven Del Pozzo - C.K. Cooper & Company

Is there any way to quantify that for the future, the properties which you have the severance tax reimbursements?

Roland Burns

Well, many of the new properties end up qualifying. But you have to go through the process, so sometimes we initially pay the taxes and then if they do qualify, they issue a refund. It’s kind of an ongoing process. But generally the production taxes, the kind of trend where they are going to be tied to the greater sales price for the most part unlike most of the rest lifting cost is fixed and it tends to run about 4% of our sales in total. You should kind of look forward and assume we have 3.5% to 4% would be severance tax and then the balance of the lifting cost is more of the fixed cost, which really won’t relate to prices too much.

Sven Del Pozzo - C.K. Cooper & Company

With the current price environment, am I looking at a fourth quarter just lifting cost about the production taxes, once I calculate that number is that still kind of in the rear view mirror, in other words are costs right now going even lower given the pull back in gas prices, is there some reason to think that lifting cost would be even lower in the future quarters?

Roland Burns

Well I think that will be lower than the fourth quarter. The fourth quarter we had about $1 million of kind of additional lifting cost that were related to state ad valorem taxes, they are typically assessed late in the year, we accrue for them, but when they came in they were a lot higher than we were expecting on some properties. So we kind of had to catch up about $1 million. So I think if you look into the future, I would expect our lifting cost outside of production taxes would be about $1 million less just for that one kind of an unusual adjustment.

Sven Del Pozzo - C.K. Cooper & Company

So just to clarify, the total taxes, the production taxes and the ad valorem taxes, if we call it all production taxes altogether, it would be about $2.8 million in the fourth quarter?

Roland Burns

No, I think it would be much greater that, that domain was just a part that we figured was probably related to prior periods. So I think they have ad valorem taxes probably about double that in the fourth quarter. Usually that number doesn’t proportionally track sales prices, because they set that once a year. They won’t necessarily float with the sales price. So, we consider that more of a fixed cost.

Sven Del Pozzo - C.K. Cooper & Company

So just to clarify, the total production taxes in the fourth quarter, we will call them production taxes plus severance and ad valorem, all the taxes together would be bigger than the 1.8?

Roland Burns

1.8 is only the severance taxes.

Sven Del Pozzo - C.K. Cooper & Company

In the PV 10 calculation, the number that you gave us, the pretax PV 10, what is the future development costs used in that calculation and would you consider them to be a little bit aggressive in consideration of the fact that future development costs are probably on the decline?

Roland Burns

That’s the one cost that will, that is really out of balance in the year-end calculation, because you have to use your average development cost and typically they want to see those tie into your tier 12-month average cost and in 2008 we had a big run-up in service cost. And then you are using the December 31 prices. So, we really had very high kind of cost per well that had to be used in the reserve report, which just kind of exaggerated the price revisions. Because, we do feel like some of those costs should come down, but basically we in our total crude reserves I think the total future development cost was $495 million.

Sven Del Pozzo - C.K. Cooper & Company

So it’s going to be less than that?

Jay Allison

It should be less than that.

Sven Del Pozzo - C.K. Cooper & Company

Okay. And then finally, the G&A. Am I correct in saying that it seems like the cash portion of G&A seems to jump up in the fourth quarter versus the third quarter?

Roland Burns

Right, it was the G&A, yes, typically what happens with our fourth quarter is usually higher than the other quarters, because that’s when all of the performance bonuses that other type incentive payments are made and those were higher than they were last year, because of the higher number of we have probably a higher staffing level now and then also I mean the company had a great year, last year. But that is probably a little also wouldn’t be what, you wouldn’t assume that to be what it looked like in the first quarter and the first quarter I think G&A will be back, it will probably more like $8.5 million but no more than $9 million. So that will come back down a little bit along with lifting cost in the first quarter.

Sven Del Pozzo - C.K. Cooper & Company

And back to Fandango, the two delineation wells that are being drilled. Do you any way of knowing whether, is it too early to say whether those two delineation wells plus a discovery well will be able to drain the entirety of the field or is it too early to say at this point?

Mack Good

No they are testing different fall blocks, so the South Texas geology is such that one well doesn’t drain the whole field by any means and it’s certainly is too early to give numbers. We like what we’ve seen; we want to get some test information on both of those wells before we issue any reserve estimate.

Sven Del Pozzo - C.K. Cooper & Company

Okay. And pardon me one last question. For the DD&A rate going forward, I understand the unit escalation in the unit DD&A rate was primarily caused by negative revisions. I’m wondering if there is also a general escalation in the DD&A rate owing perhaps to increase in just plain capital cost experience during 2008 such as steel and other input cost into the well. Could you guide me a little bit?

Jay Allison

That would be true, because basically the DD&A rate is just a reflection of defining cost and when the properties are produced. So you had a combination of both, you had fairly high capital cost in 2008, which were capitalized on the successful wells. And then, I think you kind of, at the same time with taken away reserves for price revisions, you kind of had the effect of both of those effects working to raise the rate and what should lower the rate in the future would be of course lower capital cost to an extent that we can benefit from that. But also where we are really lower the rate will be when we can add the Haynesville reserves and then kind of see and since those reserves are mainly in a lot of producing fields we have now in just a different formation. That should have the effect of really helping the rate, but that will take several, that could take two to three quarters before you really see the benefit of it.

Operator

And our next question will come from the line Rehan Rashid - FBR Capital Markets.

Rehan Rashid - Friedman, Billings, Ramsey & Co.

I’m sorry. A question for Mack actually, you said one of the goals for the year is the 80-acre spacing figure that went out. What would you like to see in terms of well performance to get comfortable with the kind of 80-acre spacing thought process?

Mack Good

Well, given the wide footprint of our drilling program, we are not going to be drilling immediate offsets to initial wells, we are drilling to prove up acreage, prove up reserves et cetera. So, this year I don’t believe many of the wells that we will drill will go directly to testing the 80-acre spacing. What you want to see obviously is lack of interference between wells, you drill one well and then 80 acres away you drill another well, some time later and you would not want to see any kind of pressure draw down or interference if you did obviously you are too close.

So, and there is various tests that they can be conducted by our reservoir group here, that can also give us some hints, some pretty good hints on the viability of the 80-acre spacing. All of the data that we have to-date and as well as the other operators around suggests that 80-acre spacing currently is valid.

Rehan Rashid - Friedman, Billings, Ramsey & Co.

I guess, I’m looking at page 17 and kind of looking at the number 1 and the number 10 wells, BSMC 12, I think they are both very close to each other. Is that kind of far close enough that would give you a good feel for things or how far apart are they?

Mack Good

No, they are too far apart, Rehan.

Operator

And at this time, we have run out of time for any more questions. I will now like to turn the call back over to management for the closing remarks.

Jay Allison

Again, I don’t want anyone to overlook the fact that we had a phenomenal ‘08 year. I think there is a fine line between being very successful and having failure and I think in ‘08 we were fortunate again to have sold all of our off-shore operations and sold $138 million of our non-core properties and no one knew that we would have a couple of hurricanes, we would have material decreases in oil and gas prices and certainly no one knew the credit crisis would be as bad as it is and we have positioned ourselves for about 17% debt-to-cap, we still have 5.3 million shares of stone, which we plan on holding on to for a long time, and those shares are worth $9 or $10 or so.

We have written those down. So there is no carry forward with any issues on that in the future and we literally are focused on creating wealth by adding reserves mainly in East Texas/North Louisiana with a little bit of compliment reserves and in the Wilcox with vertical wells or directional wells in South Texas.

As Jack and some others mentioned, maybe we will put a press release out in another six weeks or so, if we have enough information that’s important for it to go out and if any thing changes, reverses of what we have been telling you, we will notify you. And I think it should be as I said earlier, we have never been positioned as a company ever to grow what we are today.

So I thank you for the hour and 40 minutes that you have been on the phone call. Thanks.

Operator

Thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Good day.

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Source: Comstock Resources Inc. Q4 2008 Earnings Call Transcript
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