Good day, ladies and gentlemen, and welcome to the second quarter Comstock Resources, Inc. earnings conference call. My name is Latisha and I will be your coordinator for today. At this time, all participants all participants are in listen-only mode. We will be facilitating a question-and-answer session towards the end of this call. (Operator instructions) I would now like to turn the presentation over to your host for today’s call, Jay Allison, President and Chief Executive Officer of Comstock Resources. Please proceed.

Thank you, Latisha, and thanks everyone for being present for the conference call. Welcome to the Comstock Resources 2008 second quarter 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 Second Quarter 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 first quarter financial and operating results as well as the results to date 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 flip over to tab two, you will see the second quarter 2008 highlights. We are pleased to be able to report another exceptional quarter and we are very pleased on how Comstock is now positioned for future growth. In this quarter, we are accounting for our offshore operations, which relate to our investment in Bois d'Arc Energy as discontinued operations given the upcoming merger of Bois d'Arc with Stone Energy. This accounting highlights our continuing onshore operations, which have had tremendous growth this year. Many of the numbers used in this presentation reflect only our onshore operations and exclude the contributions to earnings provided by the offshore operations of Bois d'Arc. In the second quarter, our revenues were $172 million, and we generated EBITDAX of $145 million and operating cash flow of $134 million. Our net income was very strong for the quarter at $83 million or $1.81 per share.…

Thanks, Jay. Our excellent financial results have been driven by our strong production growth from our onshore operations this quarter, which are shown on slide three of the presentation. In the second quarter of 2008, our production averaged to 168 million cubic feet of natural gas equivalent per day, which was 42% higher than our production in second quarter of 2007. Our production for the first half of this year was also 42% higher than production for the same period last year. Production this quarter was also up 5% over production from the first quarter of this year. Our successful drilling activities and the South Texas acquisition that we completed at the end of 2007 account for the increase. On slide three, we break down our production into our operating regions and we also separate out the properties that we are selling. The properties that we were selling were producing about 9 million per day in the first half of 2008. We will now have that production next quarter. So excluding the Gilmer Field, which we sold at our East Texas region, this region averaged 80 million per day, which was 27% higher than it was in the second quarter of last year. Production in our South Texas region, excluding the fields that we were selling, was up 156% to 64 million per day as compared to the 25 million per day rate we had in 2007. Production in our other regions averaged 15 million per day in the second quarter, which was down from the 18 million a day that we averaged in 2007 second quarter. We expect to produce between 56 to 59 Bcfe in 2008, which would represent about a 25% to 30% growth over our 2007 levels. And this is even after accounting for the properties…

Thank you, Roland, for the excellent report on the second quarter financials, again, the highest quarterly profit in our corporate history. If you turn to slide 15, we focus on our East Texas/North Louisiana region. We drilled 52 wells in this region in eight different fields in the first half of this year. All of those wells were successful. We have tested these wells at a per well average rate of 2.6 million cubic feet equivalent per day, which is a substantial improvement from our average rate in 2007 of 1.4 million cubic feet equivalent per day. The prolific wells at (inaudible) and the Taylor Cotton Valley horizontal wells account for the improved per well results. Really our per well rate has almost doubled over what it was in 2007. On slide 16, we have a map of our Waskom Field in Harrison County, Texas. We have now drilled 3 very successful horizontal wells in this field. In the second quarter, we called drilled Swift #13 well. This well was drilled to a total vertical depth of 9,540 feet with 2,947 feet horizontal leg drilled in Taylor Cotton Valley sands. We completed this well with a seven-stage frac and it tested at an initial production rate of 8.0 million cubic feet equivalent per day of natural gas. We own a 49% working interest in the Swift #13 well. Our most recent well is the Bouge well #4, which looks to be the best one so far that we drilled. The Bouge was drilled to a total vertical depth of 9600 feet with a 2850-foot horizontal leg drilled. This well was also completed with a seven stage frac and tested at an initial production rate of 10.1 million cubic feet equivalent per day of natural gas. We have a 94% working…

Thanks, Jay. On slide 19, you will see a diagram that will give you a general picture of how we plan to complete of our first horizontal Haynesville well and as Jay mentioned we've already spud this well. This picture shows that we expect to encounter our Haynesville section for 2190 feet to 250 feet thick in our first well and that we plan to pump between 9 to 12 fracture stimulation treatments across the well's horizontal lateral. Our geological work on Haynesville shows that the targeted shale section is found in the lower part of the Bouge shale interval and the depth of this Haynesville shale targeted for development varies between 10,750 to 12,000 feet deep and we believe that the shale is between 180 to 300 feet thick cross the play area. We have drilled and completed and tested six vertical Haynesville wells in different parts of our Haynesville acreage across the play and this has given us valuable information. Drilling and completing a vertical well to test the Haynesville currently costs approximately $2.1 million. The cost of drilling and completing a horizontal Haynesville well will depend upon exact location and because of this may expect those costs to vary between $6 and $8 million. The commercial development of the Haynesville definitely requires drilling horizontal wells in order to optimize reserve recovery and economics. Comstock is currently drilling our first Haynesville horizontal well in our Toledo Bin North [ph] or TBN area. Our TBN area is located just south of our Logansport field assets into (inaudible), Louisiana. We will have an approximate 88% working interest in this well. The well name is BSMC LA 7#1. We will drill this well to an estimated vertical depth of 11,400 feet at which point we which point we will drill an estimated 4000 foot horizontal lateral, and we plan to fracture stimulate this horizontal lateral in 9 to 12 stages into simultaneously flow all of the stages to sales. Comstock plan is to move in a second Haynesville horizontal drilling rig to begin operations during the fourth quarter of 2008. We will drill an estimated 40 horizontal Haynesville wells during 2009 by running 5 rigs for the year. However, our plan is to ramp to a 7 rig program by late third quarter of 2009. I will now turn it back over to Jay.

Thanks, Mack. And as Mack reported, we actually spudded that well, I believe, yesterday. Our South Texas region has displayed on slide 20. In our South Texas region, we drilled 7 successful wells in the first half of this year and we had one dry hole. These wells have been tested at a per well average rate of 3.8 million cubic feet equivalent per day. Two of the successful wells were drilled in our Las Hermanitas field in Duval County, Texas; three were in the Javelina field in Hildago County; one was in the Ball Ranch field; and one was in the Lorenz Ranch field in McMullen County. On slide 21, we have a map of our Fandango field. We purchased this well from Shell at the end of last year. We are currently building a location to drill our first well in this field. This well will target 3 potential play sands with a total reserve potential approaching 30 Bcfe. We will have 100 working interest in this well. On December 28, we covert an acquisition of producing properties from Shell in South Texas as displayed on slide 20. We acquired 70 producing wells in the Fandango, Rosita and Dinn Ranch fields, which are currently producing 22 million cubic feet of natural gas equivalent per day. The acquired properties have net proved reserves of approximately 70 Bcfe. All of the proved reserves are in the developed category. In addition to the proved reserves, we estimate that there are 18 drilling locations, which would add 50 Bcfe of probable and possible reserves, and we have identified 14 prospective drilling locations with 42 Bcfe of reserve potential. On slide 22, we covered the sale of our net profits interest properties in East and South Texas as well as two other fields…

(Operator instructions) Our first question comes from the line of Wayne Andrews from Raymond James. Please proceed. Wayne Andrews – Raymond James: Thank you. And good morning, gentlemen, congratulations on a nice quarter.

Thank you, Wayne. Wayne Andrews – Raymond James: Yes. I have a couple of questions for you. The first relates to the timing of your Cotton Valley wells. I mean, those are two very significant wells you announced in the quarter, excellent volumes at, what, 8 million and 10 million a day. And maybe, Roland, you can tell us a little bit on how long they were on in the second quarter so we can get a feel for their contribution to the quarter and what to expect next quarter?

Wayne, this is Mack. The well that came on at 10 million a day has been on for about two weeks. So it really didn’t contribute significantly to the second quarter average. We are drilling a third horizontal well in Woodlawn [ph] Fields now and we expect to get that flowing to sales this quarter. And our current plan is to drill three more horizontal wells for Cotton Valley targets throughout the year. Wayne Andrews – Raymond James: Very good that if you have continued success like that, it should have a significant impact. Next question just kind of revolves around the Haynesville shale expansion of acreage. Now, has any – I know you’ve started out with some pretty conservative estimates of what portion of your acreage might have Haynesville potential and it’s expanded. Can you elaborate on if any of that expansion was related to just the outline of the play moving and then versus how much was actually acquired as far as additional acreage?

Wayne, we haven’t moved our play boundary significantly, although it has moved certainly. The acreage that we acquired recently has nothing to do with our legacy acreage. And you are right, there may in fact be some legacy acreage that we are not counting, especially on the west side just based on how we’ve mapped it. But the additional acreage that we’ve acquired is non-legacy acreage and it’s in Louisiana. Wayne Andrews – Raymond James: Well, that certainly sounds encouraging. And can you mention – obviously I’m sure it’s a pretty difficult environment to try to acquire acreage, and what makes you think you’re going to be able to continue to compete in that area if the dollars continue to ramp up?

You’re right again. I mean, the competition is fierce, especially for core acreage. I think the competitive advantage we have is that we have rigs that are available to joint venture with certain groups. We have a number of offers that we are considering to do that. And we are not in a position where we are facing a clock issue with a lot of our leases unlike some others. So we are in a fairly enviable position as far as being able to negotiate with some of these other entities as far as partnering.

Wayne, one thing. As you know, I mean, over 17 years we’ve got a great network and reputation in East Texas/North Louisiana. We’ve had a lot of smaller companies that have come and said, we’d still like to own some of our mineral rights, can we drill some wells with you. I mean, we’ve got an inventory of – kind of transactions like that that we’ve looked at. We do have a lot of people calling and then have 400 acres or 1,000 acres, maybe even 10,000 acres, and we continue to look at those tracks. Usually those are all on a bid basis and the company that pays the most gets the acreage. We’ve been pretty disciplined on the royalties. I mean, most of the royalties are a quarter or less. We think 30% royalties is too much. So we do have some guidelines there, and even with those guidelines we’ve two things. One, we had gone from 50,000 net acres to 65,000 net acres. And I think we’ve done that with discipline. We’ve done that with free cash flow or from properties that we’ve sold. So that’s one of the important kind of bullet points at Comstock. We have not deluded the potential return of the Haynesville, much less the Cotton Valley Taylor [ph] return by either issuing some kind of convertible instrument or by issuing equity. And I think at the bottom line we can create more shareholder value by staying disciplined like that. And we do think that we can acquire another 10,000 acres between now and year-end or we wouldn’t state that, which is – it’s unusual for us to even give a goal like that, as you know, you’ve known us for 13 years or so. So we’re pretty confident we can do that within our parameters of what we think is acceptable. Wayne Andrews – Raymond James: Very good. Well, that's one of the benefits of having operated there for so long. Thanks. I’ll let some others ask questions.

Thank you, Wayne.

Our next question comes from the line of Kim Pacanovsky from Collins Stewart. Please proceed.

Hi, Kim. Kim Pacanovsky – Collins Stewart: Hi there, good morning. Sorry about that. Hi, Jay, how are you?

I’m good. Kim Pacanovsky – Collins Stewart: Good. Okay. Couple questions here. First of all, where – what parishes in Louisiana did you acquire that additional acreage in?

That would be Caddo and Bossier Parish. Kim Pacanovsky – Collins Stewart: Okay. And Mack, I’m just curious as how you came up with your first location for your horizontal and Toledo North, and if you just kind of go through the process of why you picked this location.

Sure. The geological correlations gave us a real good idea of the Haynesville thickness that we were targeting and the porosity [ph] developments within that thickness. We also have about a 12,000-acre block that this first well will provide good tests, by no means going to test the whole block, but it was a good place to get started. Almost within 45 to 60 days from now, we’re going to be moving into Logansport in drilling our first Haynesville horizontal there. Kim Pacanovsky – Collins Stewart: Okay. And you said nine wells total for the year between the Cotton Valley Taylor and the Haynesville. So if I do the math right, is that just two Haynesville wells to be drilled in ’08? Is that correct?

No. We’re going to be spudding six actually. We’re going to TD and start completion on four of those six horizontals.

I think the two would be what we consider would be completed this year.

Right.

Completed in producing (inaudible) process at year-end. Kim Pacanovsky – Collins Stewart: Okay, all right. That makes sense. Okay. And if I – have you heard anything new on Shell and BP’s activity in Toledo South?

Yes. Shell has drilled a very nice well to the east and slightly north of our Toledo Bin North acreage block. It’s kind of in between our north and south blocks. And it really supports that region. In Canada, of course, over in Red River Parish announced a very nice well, plus 10 million a day type rate. So, the data is supporting our play boundary outlines, which we like. Kim Pacanovsky – Collins Stewart: Okay. And if we could just shift over to the Cotton Valley horizontals, you show about eight other locations on your Waskom map in your presentation. Are you going to drill those locations up before you head out of Waskom, and what’s the average interest in those locations?

We’re not going to drill those up before we move out of Waskom with the rig. We are staggering our drilling opportunities there. We plan to drill four in a row. Kim Pacanovsky – Collins Stewart: Okay. In Waskom?

In Waskom. After we get through with the current well that we are drilling, which is in Woodlawn. And the average interests in those wells, Kim, is about 80% to 100% working interest. Kim Pacanovsky – Collins Stewart: Okay, great. Thanks guys. Nice quarter.

Thank you.

Thank you, Kim.

(Operator instructions) Our next question comes from the line of Ron Mills from Johnson Rice. Please proceed. Ron Mills – Johnson Rice: Good morning guys.

Hi, Ron. Ron Mills – Johnson Rice: Just going back to Haynesville for a couple questions, Jay, you mentioned your lease expirations shouldn’t be an issue. Can you walk through – of your acreage, how much of it is held by production since you have such so much legacy acreage in the area versus how much is on a drilling clock, so to speak?

Ron, this is Mack. About 40% of our acreage is HBP and the remainder are three-year term leases. Ron Mills – Johnson Rice: All right. And I know it’s been a hot topic with a lot of people in the play. I don’t know, Mack, this may be for you. Can you talk a little bit about takeaway capacity in the area and what Comstock is doing to secure takeaway capacity?

Sure. I can’t go into details about that because we are having negotiations at the moment with a number of purchasers and pipeline operators. But the bottom line to get to your question is certainly that’s something that we are addressing. The takeaway capacity currently is sufficient to handle the anticipated volumes that based on all of the public data from the various operators that are in the play, that we think would be hitting the pipes. But as the play very quickly ramps up and I’m going into – deep into next year, those volumes are obviously going to increase very quickly. So, a number of operators – pipeline operators are planning to loop their lines and lay new lines for the takeaway capacity, increasing their takeaway capacity. So, steps are underway to address that anticipated problem. We’re getting firm capacity, I can tell you that. Ron Mills – Johnson Rice: Okay. And you talked about you have one rate now, you have second rate coming, I don’t know, probably October/November time frame. And you expect to – it sounds like average five rigs next year with a hope to exit at least seven in 2009. Do you have agreements on those rig deliveries or are you just hoping to line up the access of those rigs just looking at where you stand in that regard?

No, we’ve got contracts on those rigs, Ron. And we should exit this year with four operating and very quickly get to that fifth rig in the first quarter of next year. And then we’ll add rig six and seven moving deeper into the year. But we have all of them on contract. Ron Mills – Johnson Rice: Okay. And with Hico Knowles being the other real big driver here in terms of onshore production, it looks like – can you talk about what your activity plans are there? I know the operator of a portion of it has been fairly aggressive with their activity in Hico Knowles. And any signs that Petrohawk’s activity will slow down in this play and what your plans are, given the high productivity of those wells?

Yes. We plan to drill an additional six wells in Hico Knowles. Petrohawk’s plans, of course, I hesitate to speak for them, but they have been running between two to four rigs for the majority of the year in the field. They have acquired additional acreage that we also had some interest in to the west. So they very may well move into that acreage next year. Ron, we have not heard what their plans are for next year. I think they will have – as our release indicates, we estimate 27 more locations are available between them and us, and a few of those of course will be drilled throughout the remainder of the year. And then how they plan to allocate their dollars next year given that their activity in the Haynesville, for example, I don’t know yet. Ron Mills – Johnson Rice: And then lastly for you, Roland – and Jay, you can comment too – but your CapEx increased to $410 million versus the $278 million that you had originally budgeted. It looks like, using your growth targets and assuming the costs going forward remain in line with the second quarter that you should be more than funding that increased budget internally. Is that a fair assumption for my model?

Ron, that’s a good assumption. We are at least projecting that we’ll have cash flow in excess of what that capital budget is going to require for the remainder of the year. And I think there is still some potential that we could increase the budget some more, especially based on opportunities we have to pick up acreage in Haynesville, because that's been one of the biggest components of the increase has been the acreage that we've acquired and then just additional cost of horizontal wells, which may have displaced some of the other wells that we are drilling. Ron Mills – Johnson Rice: Do you know about how much of $135 million, $140 million increase is related to acreage versus drilling for Haynesville?

I would say about $80 million of that increase is on the acreage side, Ron. Ron Mills – Johnson Rice: All right. Well, congratulations guys. Thanks.

Thank you, Ron.

Our next question comes from the line of Dan McSpirit from BMO Capital Markets. Please proceed. Dan McSpirit – BMO Capital Markets: Thank you. Gentlemen, good morning.

Hi, Dan. Dan McSpirit – BMO Capital Markets: I recognize that it’s early innings in the Haynesville shale play and that you will find a distribution of possible values with respect to the recoveries per well and yet other operators are very comfortable with stating 6, 6.5 B per well recoveries. Yet you folks are holding to this title range of 3.5 to 4, 4 Bs. I don’t want to go so far as to say that 3.5 Bs could prove meaningless here over time, but why are you sticking to that range? Why be so conservative versus others?

Dan, I’ll address that quickly. We think that all of the data that we have in our shop more strongly supports 3.5 to 4 Bcf estimate than it does a 6 to 6.5 Bcf estimate. In order to get to the 6.5 Bcf estimate, you have to include an upper bench in Haynesville. And completing that upper bench mechanically and combining it with lower bench mechanically requires a certain completion approach that we think isn’t cost effective. So we are sticking to the 3.5 to 4 Bcf until we get some more data that we think supports a higher number. Now certainly using that upper bench has a basis. You can get to that higher number, but getting the recoveries is the question.

One thing we do say, Dan, is like we were in New York and Boston about a month ago and had a bunch of meetings. We've always said that the company that maybe has spent the most and has the most information, hopefully has the most accurate numbers. So that is why we put in the presentation that these are our numbers, this is kind of our first blush look at it and the filing costs, of course, are less than $2. And if the kind of peer company numbers are correct, it will be even a more profitable play. So like Mack said, we independently came up with our own numbers and hopefully they are conservative but they are kind of what we're going to stick to right now. Dan McSpirit – BMO Capital Markets: Got it. I appreciate the fact that these wells are – while they are economic at even at $8 gas believe it or not, but with respect to completing the upper bench what is involved there, could you help me understand I guess the mechanics of that?

Sure Dan. As you know Haynesville shale is abnormally pressured. It has the higher port pressure. So in order to frac these wells the pump pressures required are quiet high and so in order to get the rate, the pump rate to create the appropriate fracture systems around the targeted shale interval you have got to go to these high pressures. In order to complete two benches you've got to be able to isolate, mechanically pressure isolate once lateral at the lower bench from the upper lateral so you can get an appropriate frac. We think that doing that mechanically is extremely difficult. It can be done but at a very high cost and so I think what is going to happen is it we're going to drill one well drill a lateral into the lower bench and drill a second well with that lateral into that upper bench and that is yet to be done to our knowledge. So that is why we take a more conservative approach to our reserve estimates because not a lot of data is available to us on the upper bench yet.

Our next question comes from the line of David Snow from Energy Equities, Inc. Please proceed. David Snow – Energy Equities, Inc.: Yes, hi. I would like to go back to the – those $8 and $10 million a day Cotton Valley wells what acre is facing those horizontal, would that be 80 acres or?

Yes. David Snow – Energy Equities, Inc.: And how much of the – you have about 2,000 acres of Cotton Valley, is that right?

Actually across several fields we have considerably more than that. I can't give you an exact number, but in Waskom we have about that. David Snow – Energy Equities, Inc.: That was from when you were at the New York IPAA, and it has probably increased as a function of more acreage or that wasn't the full amount that you specified then?

Yes, we said – we have over 200,000 net acres in this region and all of that his Cotton Valley you know because they – but what you think as Cotton Valley.

We have – I haven't got a total but we have several thousands of acres that have been identified for the horizontal drilling program? David Snow – Energy Equities, Inc.: Is there any reason that it would be several thousands rather than the whole shooting match?

Yes, because the targeted section in the Cotton Valley is called the Cotton Valley C interval and it is continuous and bounded by some shale barriers that contain the frac heights growth and you don't find that throughout the entire area. David Snow – Energy Equities, Inc.: Okay. So the rest of it is done on 20 to 40-acre vertical spacings.

Yes. David Snow – Energy Equities, Inc.: And your average recovery on those would be more on the range of 1.3 gross or something like that or how would you–?

1 to 1.5 (inaudible). David Snow – Energy Equities, Inc.: And what would be the average of the spacing on that?

On the verticals? David Snow – Energy Equities, Inc.: Yes.

Probably 40 to 60 acres. David Snow – Energy Equities, Inc.: Okay, all right. And then in your Haynesville, are you in the deeper part of the play, it sounds like you are?

Actually we're in a shallower portion as well in Northern DeSoto and in Caddo, but we have some deeper acreage positions as you go further – as you probably already know, as we go further south it does deepen, and we have some nice blocks there, and that is just parenthetically that is where Shell and EnCana have drilled some very nice wells in that deeper section. And as you go deeper your pressure also increases in the Haynesville. David Snow – Energy Equities, Inc.: Your first well is going to be in the south or in the northern end?

We are going to be in the south end of our acreage block. David Snow – Energy Equities, Inc.: Do you have – can you give us some idea what the porosity is?

We're seeing anywhere from 14% to 18%. David Snow – Energy Equities, Inc.: Okay. Well, it sounds like as a conventional porosity almost.

Yes, but it is trapped in a shale. That is what makes it very interesting. David Snow – Energy Equities, Inc.: How much of the – what is the in plays reserves per section resource per section on these two benches that you are looking at?

Well it depends on how you want to calculate that. We think it could get up to 160 to 200 days per section and what recovery factor you want to apply to it. That it the big question mark – that everyone is focused on right now. I think everybody gets to the – pretty close to the same in place gross numbers what you think you can recover. David Snow – Energy Equities, Inc.: And that 160 to 200 is for both ventures or what portion of the section is included?

Well the lower bench is probably about 120 days of that. David Snow – Energy Equities, Inc.: And the rest is upper bench.

Yes. David Snow – Energy Equities, Inc.: Okay, wonderful. Thank you very much.

You are welcome.

Thank you.

Our next question is a follow up question from Ron Mills from Johnson Rice. Please proceed. Ron Mills – Johnson Rice: Hi, Mack. You said on the porosity that you threw out there, is that what are seeing in the 6 vertical wells that you have drilled?

Yes. Ron Mills – Johnson Rice: And where – can you give us an idea as to where those six vertical wells were drilled in terms of Toledo North versus Logansport?

We drilled in Logansport and we drilled in Waskom and we have drilled in Woodlawn. We have other data from other wells to the South. Ron Mills – Johnson Rice: Okay, and then – well then one question for you, in terms of the operating costs and the DD&A and G&A, is the second quarter a good proxy as to how things should look for the remainder of the year?

Yes, I think the second quarter Ron, is a good proxy other than maybe production taxes may not be quite as high as gas prices are lower in the third or fourth quarter than they were in the second, but otherwise the cost structure now that they've got it separated between the – with the onshore continuing operations kind of separated, it's a good proxy for how we look. Ron Mills – Johnson Rice: And then your gas prices being roughly Henry hub despite your activity be in South Texas and East Texas/North Louisiana. Is that a function of the BTU content?

The BTU content typically has been pretty strong and then they you have got really strong prices in the North Louisiana area on top of that and – but overall we have been averaging very close to Henry hub, sometimes a slight discount to that number. Ron Mills – Johnson Rice: Great, and then you're hedging, do you still only have the $17 million a day you hedged related to this shell acquisition?

Right. And that acquisition runs through the end of 2009. It is about roughly 12% of the production. Ron Mills – Johnson Rice: All right, thank you.

Our next question comes from the line of Matt McGeary from Sentinel Asset Management. Please proceed. Matt McGeary – Sentinel Asset Management: Good morning, guys. I will say if the current shareholder I do commend you generating all this nice growth and outlook within your cash flow internal estimates. Most of my questions have been answered, I am just curious Jay maybe sort of conceptually given what has happened to the E&P sector, the stock market anyway. At some point does it make sense to use some of your cash to buy back some of your own stock. You know, even with all the nice certain growth avenues you have in front for you?

Yes, absolutely I think it does. If you look at the company just [ph] as you get through this one-hour conference call, I know the sector hasn't been trading well for maybe a month, but we did report an exceptional quarter, it is the highest quarterly profit in our corporate history $83 million. As Roland had said early we didn't have a mark-to-market issue or derivative issue. We didn't have to explain some kind of mythical loss, remember we had $83 million in profits and for a company our size that is pretty phenomenal. Then going back to your statements, in other words, did we feel comfortable in purchasing stock? Well, let us look at the underlying foundation of the company, East Texas/North Louisiana we've increased our budget maybe $130 or $135 million this year, a lot of that is in East Texas/North Louisiana probably as Roland said 80%, 90% of it and then you say well what about the quality of our wells. We drilled 52, we’ve hit 52, and the IP rates have almost doubled. We were at $2.6 million a day this year. Last year for the year we averaged $1.4 million. So, we are very comfortable with our exposure in East Texas/North Louisiana. We have added another 15,000 net acres and we didn't press releases to tout it. We kind of went under the radar to do it and we kept our discipline. At the same time, we didn't issue equity to everybody to pay for it, because we don't have to. Quite frankly, before we even sold Bois d'Arc and I hope that occurs on the 28th, we were able to create our own internal cash flow because we haven't been hedged and we did these net profits and we reduced our cap, our debt…

Latisha, is that it? It is an hour or so.

At this time, we are running out of time. I will like to turn the call back over to Jay Allison.

All right again, I want to thank all of you for especially hanging on to the call to the very end. I know that this sector is not trading very well; there is nothing we could do about that. We did plan on delivering good results and if we don’t it won’t be because we didn’t try. So, thank you again for all the questions. They were good questions and for the support that we have had and continue to receive from each one of you. Thank you.

Thanks for your participation in today’s conference. This concludes the presentation, you may now disconnect.