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.

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…

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…

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…

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.

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…

(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?

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?

Actually no. Kim Pacanovsky – Collins Stewart: Okay that’s in Bethany-Longstreet. What you are acreage there?

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,

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?

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?

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?

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?

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.

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?

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?

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?

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?

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.

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?

Hadn’t planned one.

And our next question will come from the line of 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.

Could I get a little clarification on the transportation?

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?

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?

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

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.

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.

Our next question will come from the line of Ron 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?

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.

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?

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?

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?

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?

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?

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?

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?

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.

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?

Right.

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?

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

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?

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.

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?

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.

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.

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

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

It was pretty substantial this February.

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.

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?

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.

Just to get rid of the Collins.

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

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?

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.

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.

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.

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?

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.

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

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.

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?

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 --

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…

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

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

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.

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?

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?

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?

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?

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?

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?

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?

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?

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?

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.

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?

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?

No, they are too far apart, Rehan.

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.

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.

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