Good day, ladies and gentlemen, and welcome to the first quarter 2010 Comstock Resources Inc. earnings conference call. My name is Lacy and I’ll be your coordinator for today. At this time all participants are in listen-only mode. Later we will conduct a question-and-answer session. (Operator instructions). As a reminder this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today’s call, Mr. Jay Allison, Chairman and President. Please proceed.

Thank you Lacey and welcome everybody. Welcome to the Comstock Resources first quarter 2010 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 the presentation entitled first quarter 2010 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 2010 first quarter financial and operating results as well as updates results of our 2010 drilling program. Please refer to slide two in our presentation and note that our discussions today will include forward-looking statements within the meaning of securities laws. We believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. Please refer to page three of the presentation where we summarize the first quarter results, improved oil and gas process and strong production growth in the first quarter returned us the profitability.

Thanks Jay. On slide four we break out our average daily production by quarter and by each of our operating regions and we highlight the production from our Haynesville Shale wells in red on that chart. For the first quarter this year, our production averaged 209 million cubic feet of natural gas equivalent per day which is 34% higher than our production in the first quarter of 2009 of a 157 million per day. Production was also up slightly from our fourth quarter average rate of 208 million per day. Our East Texas, North Louisiana region averaged a 147 million per day with 54 million coming from our Cotton Valley wells and 93 million coming our Haynesville Shale wells. Haynesville Shale wells now make up 44% of our total production rate. Our South Texas region averaged 49 million per day and our other regions averaged 13 million per day in the quarter. We’re leaving our production guidance intact this year and still expect production in 2010 to approximate 77 Bcfe to 82 Bcfe which would represent about a 18% to 25% growth over 2009’s production. Oil prices were very strong in the first quarter which we cover on slide five. Our realized average oil price increased 91% in the first quarter of 2010 to $67.08 per barrel as compared to $35.03 per barrel in the first quarter of 2009. Our oil price in the first quarter averaged 85% of the average benchmark NYMEX WTI price. Slide six shows our average gas price which also improved in the first quarter. Our average gas price increased 12% in the first quarter to $5.30 per Mcf as compared to $4.75 in the first quarter of 2009. Our realized gas price came in right at the average NYMEX Henry Hub gas price for the…

Thank you, Roland. On slide 16 we focus on our East Texas/North Louisiana region. We drilled 13 wells in this region in five different fields in the first quarter. All of these wells were successful. 12 of these wells were horizontal wells. We’ve tested these wells at a per well (inaudible) 12 million a day equivalent per day. The horizontal wells average 13.6 million cubic feet equivalent per day. On slide 17, we recap our holdings in Haynesville Shale play in North Louisiana and East Texas which is updated for additional leases we acquired in the first quarter and some acreage flops we’ve completed with other operators. Our acreage is highlighted in blue. We currently have 83,000 gross acres and 74,000 net acres that we believe are perspective for Haynesville development, 52,000 acres were in North Louisiana, the better part of the play. Given expected well spacing of 80 acres and an expected per well recovery of 5 Bcfe per well, our acreage could add 3.5 Tcfe of reserve potential.

Thanks Jay. Good morning everyone. Just to make sure you are all awake, I am going to give you some drilling and completion details. On slide 20, we show the results of our first 39 operated Haynesville shale horizontal wells. Since our last report, we’ve completed six more operated Haynesville Shale wells in our Toledo South Bend field in Sabine Parish, Louisiana. The sustainable forest for (inaudible) number one well was drilled to the upper section of the Haynesville Shale or Bossier shale and was completed with 16 frac stages. This was our first well drilled in Sabine Parish where we have 15,735 anchors in the play. This first well's initial production rate was 20 million cubic feet equivalent per day and we have 67% working interest in the well. We also completed two successful Haynesville Shale wells in our Logansport Field in DeSoto Parish. The Horn 5 #1 well was drilled to a vertical depth of 11,275 feet with a 4669 foot lateral. This well was completed with 18 frac stages and was tested at an initial production rate of approximately 20 million cubic feet a day. The Ramsey 4 #1 well was drilled to a vertical depth of 11,426 feet with a 4616 foot horizontal lateral. The well was completed with 18 frac stages and tested at an initial production rate of 15 million a day. We have a 100% working interest in both of those wells. In the Toledo North Bend field in DeSoto parish, we completed two successful wells. The BSMC 1 #1 and the BSMC 12 #2. We’re completed with 12 frac stages and we’re each tested at an initial production rate of nine million equivalent per day. Our next set of wells will all be completed with more frac stages and more profit. Of…

Thanks, Mack. In summary, everyone please go to slide 26. We are excited about our prospects for reserve growth this year, despite the weak natural gas prices, we are well-positioned to have substantial reserve growth at a very low finding cost. Our 2010 drilling program is estimated to cost around $385 million. We’ll focus almost exclusively on developing our Haynesville Shale acreage but do we have the flexibility to reduce this budget with three of our seven rigs coming off their contract this year, we’ll take a hard look at our budget in June when the first of the three rig contract expires. We do expect to have 18% to 25% production growth this year driven by our Haynesville Shale program and based on results we had in 2009, we think our Haynesville Shale program can add 400 Bcfe to 500 Bcfe of free reserves in 2010. We are all well positioned for future growth when gas prices improved due to the large inventory of drilling locations and the upper and lower Haynesville Shale and Cotton Valley in East Texas in North Louisiana and in the Vicksburg and Wilcox trends in South Texas. We continue to maintain a very strong balance sheet. We have $500 million available on our bank credit facility currently and $216 million in cash and marketable securities on hand. For the rest of the call we’ll take questions from the research analysts who follow the stock. We would ask that you limit your questions to two and allow the next participant to ask a question. If you have additional questions and they remain unanswered just feel free to queue again with a follow up question. We’ll put you back in line. and with that I’ll turn it back over to Lacy. Lacy?

(Operators Instructions) And our first question will come from the line of John Freeman with Raymond James.

First question I had, Roland on the lifting cost, it looks like it’s the first time in about five quarters that number went up slightly. Was there anything unusual that happened during the quarter and maybe just kind of the outlook for the specifically the lifting cost going forward?

The lifting cost, what we did starting in the first quarter of this year, it started really breaking out transportation separately and some of that cost had been netted against our gas price especially in the fourth quarter and it was a very, very small amount quarters prior to that. So on a apples-to-apples basis, the lifting cost is pretty comparable, so actually didn’t go up. That was really just this re-class that makes it appear to go up a little bit.

I understand that the transportation cost is a big chunk of that that you started outlining last quarter as well. I guess I was looking at the specific lifting cost of $0.75 versus $0.65 last quarter?

The $0.75 it was a little higher than the fourth quarter, but not all costs actually fall perfectly to each quarter. So I don’t think there is anything unusual, I think there's some kind of one time quarter cost in there. But that would take our lifting cost and total would be pretty comparable this quarter to the quarters going forward. We did have also low production taxes this quarter just due to the nature of the timing of when refunds are received for wells that qualify for tight gas credits. And sometimes that can be given the regulatory process, that doesn’t come in as smooth as you like. We have lot of refunds this quarter, so the production taxes were lower, although the fixed operating costs were a little higher, but overall the total number is going to be pretty comparable to where we’ll be this year.

On the leasing activity during the quarter of the 10 million that was identified in the Haynesville in the first quarter, from what I can tell if I'm looking at correctly, it looks like the acreage, it didn’t change a whole lot from what you had provided when you announced fourth quarter results. So is it safe to say that majority of that activity happened in the first part of the year and there’s hasn’t been a whole lot in the last couple of months?

Well John, I think the acreage did increase to a little over a thousand acres. I think if you breakdown the 10 million, what was spent in the quarter, part of that was capitalized interest which goes to all the acreage and then the balance was for actual purchases. So I think our average lease cost for actual purchased acreage in the quarter was probably close to $7000 an acre.

Okay. So leasing activity was pretty consistent during the whole quarter? Kind of just steadily through the quarter?

Right. Actually you’ll see I think as you go into the second quarter, we actually had a lot of offers outstanding. They just didn’t close in the first quarter. So we will have substantially more leasing in acreage picked up in the second quarter.

And John one our goals for this year is as we drill the 56 horizontal Haynesville wells and let's say it's 80 acre spacing which you don’t really know what that proper number is, but the industry has taken 80 acres and we agree with that. If we can replace the drill size that we drilled up this year, if we can replace that, say add another 5000 net acres in a Tier 1 area in the Haynesville, that’s our corporate goal. So our goal is to add 5000 net acres at a minimum in 2010 through acquisitions of leases.

And our next question will comes from the line of Leo Mariani with RBC.

You guys discussed potentially moving your CapEx budget around this June depending on what gas prices, any color around what type of gas price you are looking forward to keep yourself at six rigs here?

Actually we are running seven rigs now. In the beginning of March we added the seventh rig to the Haynesville program. So we are running seven rigs in that program and of the seven we mentioned that three come off contract this year and the first of those three is in June. So I think as we looked forward, we set our overall plan into the seven rigs based on around a $5 NYMEX gas price because we achieved that in the first quarter and we are obviously off of that for the month of April and May. It's not looking like we will hit that, so I think that we will have to, we do not really have a set number on the pas price that we are looking to not utilize that rig. We will have to kind of evaluate how we think the gas market looks for the next twelve months plus and just aside on if we want to continue to drill or if we want to start to pull the budget in a little bit.

We assume that if you keep a rig busy for 12 months, it costs about $55 million, so that’s an assumption that we’ve used, we tweak it based upon where service cost are and then we also say that even though the Haynesville seems to have been around a 100 years, it's also been around one year for us as an aggressive driller. I mean we have created the value in the third and fourth quarter of '07. We only drilled one Haynesville well in '08 and really starting in '09 is when we started to push for Comstock to drill its acreage. It's 130,000 net acres. So this is the second full year that we’ve had with the drilling program and unlike a lot of companies I think we only have to drill maybe three or of the Haynesville well this year that we’re drilling the whole acreage. The rest of the wells that we are drilling really continue to prove up by Toledo Bend South. We probably need to drill a lower Haynesville well and Toledo Bend South, maybe several. We need to drill some addition Bossier wells or upper Haynesville wells in Toledo Bend South. Same way with Logansport, really think through end of the second maybe third quarter once the G&G side of Comstock is confident that they totally understand our footprint in the Haynesville, then I think we do take a look and pull it back and as Roland mentioned, we have three rigs rolling out this year. One in June, one in August and one in November, so we can let those three rigs go without paying any penalty at all and we’ll take a hard look at that when it makes sense and as Roland said, the first quarter, we averaged more than $5 for our gas price so that was in our model. we thought that we had averaged a little over $5 for year. It looks like that’s not going to happen in the second quarter, so if we need to tweak the drilling program back, we will and we’ll take the first look in June. I hope that helps?

It sounds like you guys are still testing everything for the next several months and after that it will be more of a economic decision based on gas prices.

Our balance sheet got stronger from yearend to the end of the first quarter. We’ve not diluted the stockholders, our risk reward profile is not altered. I mean we’re keeping our eye on creating value and we’re not drilling these wells to hold leases. It’s a much more important reason, we are drilling these wells to figure out where the better part of this Haynesville is, whether it's Tier 1, Tier 3 and you notice that at the beginning of '09 when we drilled wells in Harrison County, then we stopped, we moved over to DeSoto, we moved to Sabine. I mean we moved the program around because we can. You will notice that the wells we drill have been north or south, we own 7/8ths of that working interest. And these other wells, some of these wells in Logansport we own a 100% off. In Waskom we own a 100% of it, it’s not like we have a bunch of partners out there that tell us where to drill and when to drill. We drill with our own people, we drill on our own acreage and we drill with our own money and if we need to stop it, then we’ll do that.

Okay. Jumping over to the Bossier wells. I think that was your second well that you guys talked about here. Just any update on your first well in terms of how it's holding up and how long the well has been in production?

The well is currently flowing approximately $12 million a day on 18 Choke, pressure is stable, it's performing extremely well. And as you mentioned an upper Haynesville or middle Bossier completion. So it really sets up the whole converse acreage block quite nicely for continued development in that part of the Haynesville.

Okay, and roughly how long is that well been producing?

About a month and half, six weeks.

Okay. Jumping over to Waskom, it looks like you had a pretty good well this quarter just any observations about the kind of quality your acreage there. It seems as though it's one of the better East Texas wells, so any thoughts on kind of permeability and porosity in that area? And the size of your expedition there?

The porosity is anywhere from 10 to 12%. Perm as it is and the rest of play in the nanodarcy range. I think what we believe is that not just on the Texas side, but also on the Louisiana side by the increasing the number of stages in the profit loading per stage, you get a more effective completion of reservoir and the amount of proppant, the type of proppant placed in sequence will change depending upon what locale you are in within the play. There is no doubt in our minds that we will see improved performance on the Texas side and Louisiana side by increasing the number of stages and proppant pump on the overall completion. And don’t forget on the Texas side, another important part of the equation is how long can you drill your laterals. It's much easier in Louisiana because you are on section basis for your drilling units. In Texas, things aren't configured quite as neatly and as nicely as it is in Louisiana. As far as the drilling units go. So the other key is to be able to drill 4000 to 5000 foot lateral and then to complete with 18 stages with the increased profit loading.

And our next question will come from of Noel Parks with Ladenburg Thalmann.

Looking at the rest of year, your production guidance based on the end of last year being so strong and that being our run rate going forward. You know with basically flat production I think you will get to about 17% year-over-year growth. So that strikes me as conservative at this point, is that basically your intention just to try to keep it really conservative for next year or for this year?

We’ve been conservative as you might recall from the very beginning in Haynesville with our EURs and our production forecast. There’s a number of variables at work and we’re testing a number of them. We've just started completing our wells with the increased number of stages and propant loading. We believe that’s the right way to go is through the other major players or operators in play. We’re also looking at the effect of flowing the well at a reduced rate in order to achieve a better EUR and as a result, better economics. The purpose of choking the wells back is to sustain the bottomhole pressure for a longer period of time, the theory being that it will allow the fracture networks to remain open for an extended period of time that will allow the reservoir to produce at higher rates later on in the life of the well. So we have a lot of evidence that supports that. So we’re testing that in some of our wells. So the guidance that we’re putting out there tries to accommodate all of those variables.

In corporate life, you are going to disappoint people with some number. I mean just because you think it will, you can achieve it and you might not be able to do that. So what we’re trying to do is we've been as a management group together at least 15 years, maybe 20. So we try to risk adjust any projection hopefully to the middle, lower end and we won’t disappoint you.

Just give us your thoughts on the differentials you expect in the Haynesville through the rest of the year. I did hear what you were saying about transportation part of LOE is going to go up a bit and then just about your overall cost trend expectations, can you talk a little bit about LOE. I think also you said DD&A probably would get a bit lower going forward, I just wanted to follow up on that.

I am sure though on our cost structure we think that the lifting cost, the variable part of production taxes and gathering will kind of stay fairly consistent, although production taxes can be, were low this quarter compared to normal, maybe just because of a lot of refunds. Although we still have a lot of those refunds coming in during the year as we, as our new wells are mostly going to qualify for some of the tight gas rebates that are available. Gathering is going to be a very variable cost and I think that’s going to be a similar rate, for the product, the production we have every quarter. And but our NYMEX price realizations, they will be stronger since we are selling further down the line and so that will be like this quarter we averaged exactly at NYMEX company wide and I think that’s probably close to where we expect it to be, you know depending on what happens to the gas market and some regional differences start cropping up later. DD&A, what’s happened is that the Haynesville takes over more of the production and some of those fields have low refining costs. It's gradually lowering the rate, you saw the rate come down a little bit this quarter. So as the Haynesville production which was 44% this quarter creeps up to over 50% I think you still, if you see that rate improving but varies a few pennies a quarter.

And our next question comes from the line of Brian Corales with Howard Weil.

It sounds like you all started restricting some of the flow rates for these Haynesville wells, can you all maybe talk about what kind of flow rates you are seeing after say 30 to 60 days with those. Are they better than the previous wells.

We’ve just started that whole process and so we don’t have 30 days worth of comparison history that we can point to, but we’ve seen data to suggest that and a number of examples that we’ve seen that demonstrates that the cume, curves for a well that’s choked back in different places in the play require different choke settings within the context of the definition of what choke back is. but that you can get the same cume production that you would versus a well that was produced in a standard manner, say a 26 choke being the standard choke setting for a new completion versus a 16 or an 18 choke setting on the choke back comparison wells that are similar in every other way and you will the cume curves will cross in about 10 months to a year and four months and the net production rate will be the same about six months later. So you’ve got those elements, but the real payoff is that you get a softer decline on the choked back well because the idea being is that you are keeping those hydraulic fractures that you created via however many stages you pumped, frac stages you pumped open and more conductive over a longer period of time. So your EURs, then again we have seen evidence of this specific data that confirms a 20% to 30% EUR improvement is the result of that. But Comstock has just started looking at that on a very surgical basis and so I can't give you 30-day comparisons.

With the longer laterals and more frac stages, more proppant, what are you all seeing on the near term or the recent AFEs?

Well, there is a number of things that work there and I’ll try not to get too much detail into the answer, but all of the frac vendors, all of the high pressure pumping service providers, the wireline services, the perforating services, et cetera. Costs have increased because of the demand for those services within the Haynesville play and other shale plays in the region. And so, you have that regardless to how many stages you pump. And then the increased number of stages that we pump obviously takes more time to accomplish if the vendor, the pumping service vendor has gone to daylight service only and there was a time when the vendors were predominantly providing 24 hour operations. Well the problem there is that it has been extremely difficult to find time, the vendor is finding time to maintain their equipment and long story made short, a number of them have gone to daylight operations only for half to two thirds of their crews. So, that has drawn out the amount of time that it takes to complete the well and as a result the daily costs for the completion is gone up. So, you add more proppant, more stages, you add the elements that I mentioned, you are approaching a $9 million D&C for an 18 stage well at this time given the current cost structure.

Can you make any comment on the thought process for the Stone shares in terms of playing the cell? Obviously we saw the original block but any color there would be helpful?

Several weeks ago we did sell them below the reporting number. So we own less than 10% of stone now, we monetized $10.5 million of stone shares. We think stone is under valued and I don’t think that you own Comstock stock because you want to own Stone. I think you own Comstock because you want us to invest those dollars somewhere else and over some amount of time, we will divest ourselves of the stone shares. We are not restricted at all and we are taking the first step toward doing that. When we think the time is right, we will continue to monetize that.

And your next question come will come from the line of Ray Deacon with Prichard Capital.

I wanted to follow-up on the comment Mack made and in terms of delineating the areas where you are active and do you have an EUR range based on Toldeo Bend North, Sabine, Harrison that you can talk about or are you just kind of in that process and you will done with it by yearend I guess?

We do have some numbers, but they are being altered by the new completion design that we are rolling out to our wells and then you couple that with the choke back process that I described earlier. So the EUR numbers that I would cite are really in flux. We’ve used a 5 Bcf EUR across the play. The statistical representation of what we think is occurring. We think for example when we know that given 12 stage completions and not considering the impact of choke back settings in Logansport, we have some wells that are approaching the seven to eight Bcf EUR. In Benson, we’re using a four to five Bcf EUR. Toledo Bend South, we’ve just drilled our first well. It looks extremely good by pressure versus rate comparison. So we need some more data to firm our EUR extrapolations, but you’re again looking at six (inaudible) there.

In terms of Waskom, I was surprised by the rates there this quarter and I think your takeaway is very good there. Is it just you will drill one well there this year and can maybe just generally talk about takeaway in different areas? Are there any bottlenecks out there that you are worried about?

We’re only going to drill the one well in Waskom. Everything is HBP. So we drilled our Waskom well really as an exception to that rule, we had to protect some acreage and we did that. We’re going to drill one other well on the Texas side and that’s it for the year. That’s our current plan. And takeaway issues, we have none that I am aware off. Our VP of marketing has done a excellent job of scheduling our firm capacity on the long haul pipes. We’ve got gathering agreements established that provide the appropriate takeaway at the appropriate time so we are in great shape, I don’t see any problems in any of our areas.

Our next question will comes from the line of Ron Mills with Johnson Rice.

I have a question, it has to do with the frac, the spread of sales times, you’ve gone from mid to upper 70s to the low 90s in terms of number of days and is that a trend that you expect to continue to lengthen or do you think that plus or minus 95 days is going to be more of the standard?

We want that to come down obviously. It creeped up for a couple of reasons, one as I described earlier the vendors pulled frac dates because they needed additional time for their maintenance and so we are not the only ones with wells waiting on completion. We’ve also as I described experienced some delays as a result of the vendors going to daylight operations and we made a decision to use two of our wells this quarter and delay their completion because we decided to use those wells as monitoring wells for micro seismic on an upper Haynesville well that we wanted to get some specific fracturing data on, so we could optimize our subsequent frac designs in upper Haynesville completion. We contributed to that problem by using those two wells for that reason. We are working with the vendors to get additional frac dates so we can move that spud to sales time. Our drill time curve as you can see is excellent. We’re just stacked up a little bit on the frac dates and we’re working hard with vendors to rectify that and we think we can. So I believe that spud to sales time will come back down.

Who are your primary frac vendors now? And then from a production standpoint, given a little bit longer spud to sales, sounds like the beginning of testing these restricted chokes. Are those two issues baked into your 18 frac set target?

Ron, the two major vendors for fracing are Halliburton and B.J. and of course, we’re working with the others as well. On your question on production I think that we have enough conservatism in our production to account for the longer times to bring the wells to sales and maybe some of the reduced choke production scenarios. I think it’s just the transition from some of those items, from the quarter before where we had short connect times because of the availability of services and then the higher flow rates. You probably saw a little bit of that this quarter where you don’t have quite the high flow rates, but hopefully that benefits us in future quarters where we don’t have as higher decline rates either, but we keep our drilling budget intact and the seven rigs, we feel good that we will have the production growth we promised in our guidance.

And our next question will come from the line of Richard Tullis with Capital One Southcoast.

Looking at the drilling plans for the rest of this year going forward, do you foresee any potential to drill maybe the more liquids-rich parts of your acreage, maybe the padded, anything like that?

No, we are dedicated at the moment to drilling our Haynesville acreage and evaluating the completion designs that I mentioned earlier and as you know the Haynesville is dry gas.

Looking at that well in Harrison County that was recently completed, the 12 million a day. What was the cost of that well, or do you have an EUR estimate at this point?

The EUR would be speculative, it's pretty early in the life of the well, so we are going to have to differ to answer that question later and the drilling complete on that well, which was drilled earlier in the year was about $8 million.

And our next question will come from the line of Kim Pacanovsky with MLV.

In Toledo South, you obviously only have your own single data point there. But it was a pretty phenomenal well. If you continue your drilling program down there this year and you see consistently strong results, will you shift some of your dollars to that area from some of the less prolific areas that you are drilling?

Well, that’s a great question and the short answer is sure. We have the flexibility to do that and as matter of fact we are going to be studying another well in that part of the world very soon, so the answer is yes, you bet.

With everybody moving toward the increased use of proppant, are you seeing any issues with proppant yet again?

Well another short answer is yes but fortunately you know we planned well ahead for our proppant needs, so we are covered especially over the next couple of quarters, but there is an increased demand for the proppant and it is a concern that all the operators have.

And our next question will come from the line Jeff Robertson with Barclays Capital.

Can you talk a little about the cost of the wells with the new completion designs you all are using. And also secondly, can you talk a little about the geologic differences in the shale between North Toledo Bend and South Toledo Bend and Logansport where based on slide 24 it looks like you've got a little bit lower IPs in North Toledo Bend.

Sure Jeff, the costs are being impacted by the increased demand for high pressure service in the Haynesville as well as other shale plays in the region. And so the drilling complete cost have certainly come up from third quarter last year to where we were we had drilling complete cost of around $8 million to our current $9 million estimate. That is partly as a consequence of the increased demand, but it is also a consequence of the vendors, the high pressured service providers, taking a step back from their 24 hour operations and going to daylight operations only, so they can provide some time for equipment maintenance. There’s also some equipment re-design work going on, on their pumps but I won't get into that. They have had problems on the [fluid] ends and getting deliveries from their manufactures on the [fluid] ends to replace those that are damaged beyond repair has created a bit of problem of getting equipment back into service. So as all of those things add up to increased drilling, increased completion cost. The drilling cost have stayed pretty much the same. Most of the increases that we’ve seen are on the completion side. On your question about the geological differences between Toledo Bend North and South and Logansport, we find the porosity and porosity thickness and the clay content of the shale are the primary drivers. The lower Haynesville thins as you go south, the upper Haynesville thickens in certain places along with improved [proxy] development as you go south. Some operators are pumping over 20 stages, there has been an indication of one operator pumped 28 stages. The bottomline though is that there has be a cost-effective optimum and that's yet to determined in any of the above examples. So that’s where we benefit from our relationships with certain other operators trading data and getting information across the board so that we can arrive hopefully at that optimum solution faster than we would otherwise

And your next question will come from the line of Dan McSpirit with BMO Capital Market

You speak to reserve growth this year, or at least what is estimated, 400 Bcfe to 500 Bcfe this year. One, can you shed some light on PDP and pud mix of that number to the number of offsets per well maybe assumed in that estimate. And three, is there any upside to that estimate that range of 400 Bcfe to 500 Bcfe with respect to the new completion design, and especially the restricted rate program?

The 400 Bcfe to 500 Bcfe as far as the split between the PDP and puds, we’re only assigning to offset puds to every PDP. All the wells we’re drilling this year set up to offset puds, there are no cases that I’m aware of that doesn’t, if there are there might be one or two, that don’t set up to two puds. So that’s the distribution on the reserve question. On the upside, it’s still unknown because we’re evaluating the improvements that we are gaining through the 18 stages and versus 12 to 14 stages in earlier completions as well as the increased proppant loading. And we’re also taking a hard look at the impact of choking the wells back slightly in order to soften the decline and improve EUR and of course, that data like I mentioned earlier in the call that we have a lot of data that we have looked at, that is supportive of that. Conclusion, we need to get our own wells data set that we can use for comparison purposes to support those improved EURs. So that’s the upside.

We see the industry here chasing the oil story. Many of your peers are doing this almost without discipline. Can I get your thoughts on this trend. Do you feel it is necessary for Comstock, to maybe diversify its own asset base and/or do you continue to buy where others are not, that is natural gas assets?

You made a comment of keeping your eye on the larger value creation and which companies have the best torque with the recovery. I would tell you that the one I mean we demonstrate that we care where the stock price is because we hadn’t diluted anybody for five years. I think the second thing is we continue to maintain a very strong balance sheet and it gets stronger from year end to where it is today. I know we have been criticized a little bit for continuing to drill some Haynesville wells, but we are not drilling these wells to hold acreage, we really are drilling them because it's a G&G play, it's not some company that we bought and we are drilling development wells. We are still trying to kind of crack the code on the science. I think when we are totally comfortable as a company, then we will pull that back in, I do think that if you look at our other regions where we have 13 million to 14 millions a day production and 54 plus Bcfe reserves which is San Juan, which is Mid-Continent and in the rural Mississippi area. If you add all that up it's about 60% oil. One of our goals is probably to monetize that. If you were to monetize that and you were to go ahead and sell the remaining Stone shares at some point in time, you would add somewhere north of $200 million to add new core acreage in the Haynesville or add a new core area. We were in the Haynesville probably nine months before it became public. We are always looking at new areas to compliment our existing area, but I think right now our goal is to prove this up and if we need…

Ladies and gentlemen that’s all the time that we have for our question and answer portion. I would now like to turn the call back over to Chairman and President, Jay Allison for closing remarks.

I think with the question that Dan asked me which was accidental, those were one of my closing remarks. We didn’t have a really great quarter, we continue to keep our strong balance sheet. We started proving up Toledo Bend South which there were bunch of naysayers out there that we might not like Toledo Bend South and we do. I do think that we continue to focus on our reserve growth this year. We will have production growth, but reserve growth is equally is important. We don’t see any point of time where we have to access the capital markets and our risk reward profile really is not altered. Cost have gone up a little bit, but I think our EURs will continue to go up. So, with that I’ll thank you for the hour or so that you have spent. I know it is a busy morning and we are always thankful for your participation and ownership of the company. Thank you.

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