Comstock Resources Inc (CRK) 2010 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the first quarter 2010 Comstock Resources, Inc. earnings conference call.

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.

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 selecting Presentations. There you will find a 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 update the results of our 2010 drilling program. Please refer to slide two in our presentations and note that our discussions today will contain forward-looking statements within the meaning of Securities Laws. While we believe the expectations and such statements to be reasonable there can be no assurance that such expectation wills prove to be correct. Please refer to page three of the presentation where we summarize the first quarter results. Improved oil and gas prices and strong production growth in the first quarter returned us to profitability. In the first quarter our production increased to 18.8 Bcfe, 34% higher than production in the first quarter of 2009. With higher prices and production, we reported revenues of $106 million, generated EBITDAX of $80 million, and had an operating cash flow of $72 million, or $1.57 per share. We reported net income of $7 million, or $0.16 per share.

We continue to have strong results in our Haynesville shale drilling program. 44% of our Company-wide production is coming from the Haynesville shale. We drilled 14 successful wells including 12 horizontal Haynesville shale wells in the first quarter. One of these wells was drilled in our South Toledo Bend area in Sabine Parish, Louisiana. This well was successfully completed in the Upper Haynesville, or Middle Bossier section, with an initial production rate of 20 million cubic feet equivalent per day. This well has proved up much of our acreage in Sabine Parish. We are on track for another year of strong reserve growth driven by our Haynesville shale drilling program. Our balance sheet continues to be very strong which will allow us to pursue our business plan this year without having to rely on the capital markets for any funding.

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

Thanks, Jay.

On slide four we break out our daily average 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 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 147 million per day, with 54 million coming from our Cotton Valley wells and 93 million coming from 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 will represent about an 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 quarter. We had 12% of our gas production hedged in the first quarter of 2009, and none of our production is hedged this year.

On slide seven we cover our oil and gas sales. Improved oil and gas prices, combined with a 34% production increase caused our sales to grow by 55%, to $106 million in the first quarter. Our earnings before interest, taxes, depreciation, amortization, and exploration expense and other noncash expenses, or EBITDAX, grew by 77% to $80 million as shown on slide eight. On slide nine, we cover our operating cash flow. Our operating cash flow for the quarter came in at $72 million, a 60% increase as compared to cash flow of $45 million in 2009's first quarter.

On slide ten, we outline the earnings. We reported net income of $7 million, or $0.16 per share, compared to a net loss of $6 million, or $0.12 per share in 2009's first quarter. The improved oil and gas prices and the production growth account for the turnaround. We also benefited from a low income tax rate in the first quarter which is a function of the projected tax rate for all of this year. On slide 11, we show our lifting costs per Mcfe produced by quarter. This quarter we have broken out our lifting costs into three components; production taxes, transportation, and then other field level operating costs. With our increasing Haynesville shale production, we are transporting more of our gas to the longer haul pipelines rather than selling our gas at the wellhead. The result is an increase in our lifting cost which is being offset by improved gas price realizations.

Our total lifting cost averaged $1.08 per Mcfe in the first quarter 2010 as compared to $1.20 per Mcfe for the first quarter of 2009. Production taxes made up $0.09 of that rate, and our transportation costs averaged $0.24 in the first quarter. Field operating costs averaged $0.75 this quarter, which was way down compared to the $1.03 that it averaged in the first quarter of 2009. Improvement in our lifting costs field operating cost is basically due to the higher production level, as many of these costs are fixed in nature.

On slide 12, we cover our cash G&A per Mcfe produced by quarter, which excludes stock-based compensation. Our General& Administrative costs decreased to $0.30 for Mcfe in the first quarter of 2010, as compared to $0.43 per Mcfe in the first quarter of 2009. Improvement is due to the higher production level combined with lower overall G&A costs in the quarter. Our depreciation, depletion, and amortization per Mcfe produced is shown on slide 13. Our DD&A rate in the first quarter averaged $3.15 per Mcfe, an improvement from the $3.36 rate we had in the first quarter of 2009. Our DD&A rate this quarter also decreased $0.06 from the $3.21 we averaged in the fourth quarter of last year.

With the Haynesville shale production continuing to increase, we expect to see our DD&A rate improve further in 2010. On slide 14, we detail our drilling expenditures. We spent $94 million in the first quarter for our drilling program, as compared to $97 million that we spent in 2009's first quarter. We spent most of that $91 million in our East Texas/North Louisiana region with only $2.5 million spent in our South Texas and other regions in the quarter. Almost $10 million of our $94 million that was spent in the first quarter was spent on leasehold cost and was mainly to acquire additional leasehold in the Haynesville shale play.

Slide 15 presents our capital structure at the end of the first quarter. On March 31 we had $122 million in cash on the balance sheet, and $94 million in marketable securities on hand. We had a total of $471 million of total debt, including the $175 million of our 6.78% senior notes and $296 million of our new 8.38% senior notes. We had nothing outstanding on our credit facility, which has an unused borrowing base of $500 million. Our bank group recently reaffirmed the borrowing base on April 30th. Taking into account the cash on our balance sheet and our marketable securities and the unused $500 million buying credit line, we have $716 million in total liquidity. Our book equity at the end of the quarter was $1.1 billion, making our net debt only 16% of our total capitalization.

I will now turn it back over to Jay.

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 have tested these wells at a per well average rate of 12 million a day equivalent per day. The horizontal wells averaged 13.6 million cubic feet equivalent per day. On slide 17, we recap our holdings in the Haynesville shale play in North Louisiana and East Texas which is updated for additional leases we acquired in the first quarter and some acreage swaps we have 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 are 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 have 3.5 Tcfe of reserve potential. On slide 18, we show the acreage that we think has potential for the development of the upper Haynesville shale, or Middle Bossier shale. Our acreage is highlighted in blue. We currently have 54,000 gross acres and 46,000 net acres that we belief are perspective. Given similar expected well spacing of 80-acres and expected per well recovery of 5 Bcfe per well, our acreage could have 2.2 Tcfe of reserve potential. On slide 19 we combine the two plays. Acreage with exposure to both plays is counted twice. In total we currently have 137,000 gross acres and 120,000 net acres. The combined reserve potential is 5.7 Tcfe.

I will now turn the call over to Mack Good to go over some of the recent drilling results. Mack?

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 South Toledo Bend field in Sabine Parish, Louisiana. The Sustainable Forest 3#1 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 acres in the play. This first well's initial production rate was 20 million cubic feet equivalent per day. We have a 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 debt of 11,275 feet with a 4,669 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 4,016 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 100% working interest in both of those wells.

In the Toledo North Bend Field in the DeSoto Parish, we completed two successful wells; the BSMC 1#1 and BSMC 12#2. We completed these wells with 12 frac stages and were each tested at a initial production rate of 9 million equivalent per day. Our next set of wells will all be completed with more frac stages and more proppant. All of the wells that I have just discussed are in the Louisiana Haynesville play. But we also drilled one Haynesville well in East Texas in our Waskom Field. The Clark H#1 well was drilled to a vertical depth of 10,908 feet with a 4,261 foot horizontal lateral. This well was completed with 18 frac stages and was tested at an initial production rate of 12 million equivalent per day, and we have a 100% working interest in this well. This is one of the better Haynesville completions on the Texas side of the Haynesville play.

Slide 21 summarizes some of the changes we've made since we first started operations in the Haynesville play. You can see that we are now drilling the maximum length horizontal lateral that is possible in our individual Haynesville drilling units, with some of our laterals now approaching 4,800 feet in length. In addition, we are currently pumping 18 frac stages across these lateral lengths compared to the 10 to 12 stages we were pumping in our earlier wells. Not only are we currently pumping more frac stages but we are pumping more proppant per frac stage. This obviously results in more proppant placed per the overall lateral completion. In fact, you can see from the table that we have increased our proppant loading to around 220,000 pounds per stage, which is an increase of approximately 10% over previous designs. So what all this means is that we are pumping more proppant over smaller frac stages.

As a result, we believe that this adds up to a more efficient and effective completion of the Haynesville shale reservoir. But there is no doubt, that as we get additional information, we will continue to change our completion designs and each of our Haynesville shale operational areas in an effort to find the optimum completion design that is best for each one.

Continuing on to slide 22, we again show the number of days it has taken to drill the 48 horizontal Haynesville wells that we have drilled to date. Our average drill time for all 48 wells is 41 days. The average drill time for our first five wells drilled was about 49 days, compared to 33 days average drill time for our last five wells. Our recently drilled Nelson well on the Texas side holds our record for the best drill time at 25 days. We cannot find any evidence that a well has been drilled faster than that in the play.

On slide 23, we show the number of days it has taken to connect each of our 39 operated horizontal Haynesville wells currently flowing to sales. Comstock's average connect time is 97 days for all 39 wells currently flowing to sales. Our average days from spud to sales for our first five wells was 110 days, compared to 91 days for our last five wells. We are experiencing longer lead time for well completions, which has added about 30 days to our average spud to sales time from where we were last quarter.

Slide 24 covers our planned activity this year to further develop our Haynesville shale acreage. All but three of the planned 56 wells will be drilled in a more prolific part of the play in North Louisiana. 27 wells are planned for Logansport and 25 wells are planned for Toledo Bend North and South. Most of the wells will target the lower Haynesville shale, but we also plan to drill up to 15 upper Haynesville shale or Bossier shale wells this year.

Finally, our South Texas region is displayed on slide 25. We drilled one well in this region in the first quarter as a competitive drainage well. The Julian Pasteur #4 was drilled in our Ball Ranch field and this well tested at a initial production rate of 8 million equivalent per day.

And now I will turn the call back over to Jay.

Thanks, Mack. In summary, would 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 estimated to cost around $385 million will focus almost exclusively on developing our Haynesville shale acreage. We do have the flexibility to reduce this budget with three of our seven rigs coming off their contract this year. We will take a hard look at our budget in June when the first of the three rig contracts 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 new reserves in 2010. We are well positioned for future growth when gas prices improve with a large inventory of drilling locations in the upper and lower Haynesville shale and Cotton Valley in East Texas and 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 will 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 that remain unanswered, just feel free to queue up again with a follow-up question. We will put you back in line. And with that I will turn it back over to Lacey. Lacey?

Thank you.

(Operator Instructions). Questions will be taken in the order received.

And our first question comes from the lines of John Freeman with Raymond James. Please proceed.

Good morning, guys.

Morning.

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

Okay, John, the lifting cost. What we did, starting in the first quarter of this year, we started breaking out transportation separately and some of that cost had been netted against our gas price, especially in the fourth quarter. It was a very small amount in quarters prior to that. So, if you really, on an apples to apples basis, the lifting cost is pretty comparable. So it actually it didn't go up. It was really just this reclass that makes it appear to go up a little bit.

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

Okay. The $0.75 it was a little higher than the fourth quarter, but I think that is just - - not all costs actually fall perfectly to each quarter, so I don't think there's anything unusual. I think it's just some kind of one-time quarter costs in there. But I would think our lifting cost in the total will be pretty comparable this quarter 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. Sometimes that can be given the regulatory process that can be - - that doesn't come in as smooth as you like. So we had a lot of refunds this quarter, so the production taxes were lower, although the fixed operating costs were a little higher. But overall I think the total number is going to be comparable to where we will be this year.

Okay. Thanks. My second I guess and last question before I turn it over to somebody else. 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 am looking at it correctly, it looks like the acreage it didn't change a whole lot from what you provided when you announced the fourth quarter results. So is it safe to say the majority of that activity happened in the first part of year and there hasn't been a lot in the last couple of months?

Well, John, I think the acreage did increase about 1,000 acres, a little over 1,000, kind of rounded but a little more than 1,000 acres. I think if you break down the 10 million, what was spent in the quarter, part of that was capital on 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 $7,000 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 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 add, have substantially more acreage in the second quarter.

John, one of our goals for this year is as we drill the 56 horizontal Haynesville wells, and let's say it is 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 sites that we drilled up this year. If we can replace that and say add another 5,000 net acres in the Tier 1 area in the Haynesville, that is a corporate goal. So our goal is to add 5,000 net acres at a minimum in 2010 through acquisitions of leases.

Great. That is very helpful. Thanks, guys.

Thanks, John.

And our next question will come from the line of Leo Mariani with RBC. Please proceed.

Hi, good morning, guys.

Hi, Leo.

You discussed potentially moving your CapEx budget around this June depending on what gas prices do. Just any color around what type of gas price you are looking for to keep yourselves at six rigs here?

Leo, this is Roland. 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. 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 look forward - - we set our overall plan using the seven rigs based around a $5 NYMEX gas price. Of course we achieved that in the first quarter and we're obviously off of that for the month of April and May. It is not looking like we will hit that. We don't really have a set number on the gas price that we are looking to not utilize that rig. We will have to evaluate how we think the gas market looks for the next 12 months plus, and just decide on if we want to continue to drill or if we want to start to pull the budget in a little bit.

Leo, this is Jay. We have said 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 what service costs are. And then we also say that even though the Haynesville seems to have been around a hundred years, it has only been around one year for us as an aggressive driller. I mean you have to create the value in the third and fourth quarter of 2007. We only drilled one Haynesville well in 2008. And really starting in 2009 is when we started the push for Comstock to drill its acreage, it's 130,000 net acres. So this is the second full year that we have had with the drilling program.

Unlike a lot of companies, I think we only have to drill maybe three or four of the Haynesville wells this year that we are drilling hold acreage. The rest of the wells that we are drilling really continue to prove up like Toledo Bend South. We probably need to drill a lower Haynesville well in Toledo Bend South, maybe several. We need to drill some additional Bossier wells or upper Haynesville wells in Toledo Bend South. Same way with Logansport.

Really I think through the end of the second quarter maybe third quarter, once the G&G side of Comstock is confident that they totally understand our footprint in the Haynesville, we will take a look and consider pulling it back. As Roland mentioned, we have three rigs rolling off 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. We will 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 would average a little over $5 for the 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 will take the first look in June. I hope that helps.

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

Well, you need to know - - our balance sheet got stronger from year-end to the end of the first quarter. We have not diluted our stockholders. Our risk reward profile is not altered. We are keeping our eye on creating value, and we are not drilling these wells to hold leases. It is a much more important reason. We are drilling these wells to figure out where the better part of this Haynesville is, whether it is Tier 1, Tier 2, or Tier 3.

And you've noticed that at the beginning of 2009 when we drilled wells in Harrison County, then we stopped. We've moved over to DeSoto, we moved to Sabine. I mean we've moved the program around because we can. You'll notice that the wells we drill, if the drill had been north or south, we own seven-eights of that working interest. And these other wells, some of these wells like Logansport, we own 100% of. In Waskom we own 100% of. It is 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. If we need to stop it, then we will do that.

Right. Jumping over to the Bossier well. I think that was your second well that you talked about here. Just any update on your first well in terms of how its holding up and can you remind us how long that well has been in production?

Leo, this is Mack. The well is currently flowing at approximately 12 million a day on an 18 inch choke. Pressure is stable. It is performing extremely well. As you mentioned it is an upper Haynesville or Middle Bossier completion. So it really sets up the whole Converse acreage block quite nicely for us for continued development in that part of the Haynesville.

Okay. And roughly how long has that well been producing?

About a month and a half, six weeks.

Okay. Jumping over to Waskom, it looks like you had a pretty good well this quarter. Just any observations - - about the quality of your acres there? It seems as though it is one of the better East Texas wells. Any thoughts on permeability and porosity in that area? And the size of your expectations there?

Leo, the porosity is anywhere from 10% to 12%. Perm as it is in the rest of play in the nano darcy range. I think what we believe is that not just on the Texas side, but also on the Louisiana side, by increasing the number of stages in the proppant loading per stage, you get a more effective completion of the reservoir. The amount of proppants, the type of proppants placed in sequence will change depending upon what location 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 is much easier in Louisiana because you're on a section basis for your drilling units. In Texas things aren't configured quite as neatly and nicely as it is Louisiana as far as the drilling units go. So, the other key is to be able to drill at 4,000 to 5,000 foot lateral, and then to complete it with 18 stages with the increased proppant loading.

Okay. Thanks, guys.

You bet.

Thank you, Leo.

And our next question will come from the line of Noel Parks with Ladenburg Thalman & Co.. Please proceed.

Good morning.

Hi, Noel.

How are you doing? Just a few things. Looking at the rest of the year. Your production guidance based on the end of the year following so strong and that being a run rate going forward, I am sorry the end of last year being so strong and that being the run rate going forward, 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 - - for this year I should say?

It is my intention. We have been conservative as you might recall, from the very beginning in the Haynesville with EUR's and our production forecast. There's a number of variables at work and we're testing a number of them. We have just started completing our wells with the increased number of stages and proppant loading. We believe that is the right way to go, as do the other players or operators in the play.

We are also looking at the effect of flowing the wells at a reduced rate in order to achieve a better EUR, and as a result, better economics. The purpose of the choking the wells back is to sustain the bottom hole 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 are testing that in some of our wells. So the guidance that we're putting out there is trys to accommodate all of those variables.

Well - - Noel, in your corporate life, you're going to disappoint people with some number just because you think you can achieve it and you might not be able to do that. So what we try to do is, we 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 that way we don't disappoint you.

Great. My other one was, just your thoughts on the differentials, you expect in the Haynesville for the rest of the year. I didn't hear what you said about transportation, part of LOE is going to go up a bit. And then just about your overall cost trend expectations. You talked a little about LOE. And I think you said DD&A probably would get a bit lower going forward? So I just wanted to follow-up on that.

I'm sure, Noel, yes, on our cost structure, we think that the lifting cost, the variable part of production taxes and gathering are going to kind of stay fairly consistent. Although production taxes can be were low this quarter compared to normal, just because of a lot of refunds. Although we still have a lot of those refunds coming in during the year as our new wells are mostly going to qualify for some of the tight gas rebates. Gathering going to be a very variable cost, and I think that's going to be a similar rate. You will just apply that to the production we have every quarter.

But our NYMEX price realizations, they will be stronger since we are selling further down the line, and so they will be - - like this quarter we averaged exactly at NYMEX Companywide. I think that is probably close to where we expect to be depending on what happens to the gas markets, if there is some regional differences that start cropping up later. On DD&A what's happening is the Haynesville takes over more of the production and some of the fields have low finding costs, it is gradually lowering the rate. You saw the rate come down a little bit this quarter. So as that Haynesville production, which was 44% this quarter, creeps up to over 50%, I think you can still see that rate improving, but a few pennies a quarter.

Great. Thanks.

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

Hi, guys. Just kind of a follow-up to Noel's first question. It sounded like you started restricting some of the flow rates for these Haynesville wells. Can you talk about what kind of flow rates you are seeing after 30, 60 days with those? Are they better than the previous wells?

Brian, this is Mack. We've just started that whole process. We don't have 30 days worth of comparison history that we can point to. But we have seen data to suggest that in a number of examples that we have seen, that demonstrates that the cummulative curves for a well that is choked back,and 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 production that you would versus a well that was produced in a standard manner, say a 26 inch choke being a standard choke setting for a new completion, versus a 16 inch or an 18 inch choke setting on a choke back comparison wells that are similar in every other way. And you will, the cummulative curves will cross in about ten 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 pay off is that you get a softer decline on the choked back well, because the idea being is that you are keeping those fractures, hydraulic fractures that you created, however many stages you pumped - - frac stages you pumped, open and more conductive over a longer period of time.

So your EUR's, then again we have seen evidence of this specific data, that confirms that 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.

Okay. Very helpful though. And with the longer laterals and more frac stages, more proppant, what are you seeing on the near term or recent AFE's?

Well there are a number of things at work there. I will try not to give too much detail into the answer, but the - - all of the frac vendors, all the high pressure pumping service providers, the wireline services, the perforating services, etc., costs have increased because the demand for those services within the Haynesville play and other shale plays in the region. So you have that regardless of how many stages you pump.

And 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. 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 vendors finding time, to maintain their equipment. So, long story made short, a number of them have gone to daylight operations only for half to two-thirds of the crews. So that has drawn out the amount of time that it takes to complete the well. And as a result the costs, the daily costs for the completion has gone up.

So, you add more proppant, more stages, you add the elements that I mentioned, you are approaching $9 million D&C for an 18 stage well at this time given the current cost structure.

Okay. And if I could squeeze just one more question in. Can you make any comment on the thought process with the Stone shares in terms of playing the cell? Obviously, we saw the original block? But any color there would be helpful.

We, several weeks ago we did sell down below the reporting number, so we've got less than 10% of Stone now. We monetized $10 million to $10.5 million in Stone shares. We think Stone's under valued. I don't think 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 have taken the first step toward doing that. So when we think the time is right, we will continue to monetize that.

Okay, guys. Thank you.

Our next question will come from the line of Ray Deacon with Pritchard Capital. Please proceed.

Hi, Roland and Jay. I wanted to follow-up on the comment Mack made in terms of delineating areas where you're active. Do you have an EUR range based on Toledo Bend North, Sabine, Harrison that you can talk about? Or are you just kind of in that process and you will be done with it by year-end?

This is Mack. We do have some numbers but they are being altered by the new completion design that we are rolling out to the wells. You couple that with the choke back process that I described earlier so the EUR numbers that I would site are really in flux.

We have used a 5 Bcf EUR's across the plays. Statistical representation of what we think is occurring. We think, for example - - we know, given 12 stage completions, and not considering the impact of choke setting in Logansport, we have some wells that are approaching the 7 Bcf to 8 Bcf EUR. And in Benson, we are using a 4 Bcf to 5 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 are again looking at 6 B's there.

Got it. And in terms of Waskom, I was surprised by the rate there this quarter. I think your take away is very good there. Will you drill just one well there this year? And can you maybe just generally talk about take away in different areas? Are there any bottlenecks out there you are worried about?

We are only going to drill the one well in Waskom. Everything is HBP, so we drill the 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 is it for the year. That is our current plan. And take away issues, we have none that I aware of.

Our VP of Marketing has done an excellent job of scheduling our firm capacity on the long haul pipes. We've got a gathering agreement established that provide the appropriate take away at the appropriate time so we are in great shape. I don't see any problem in the any of the areas.

Thanks, Mack.

Yes, sir.

Our next question will come from the line of Ronald Mills with Johnson Rice & Company. Please proceed.

Good morning.

Hi, Ron.

I actually somehow have a question left. It has to do with the frac. To spread the sales time, you went from mid to upper 70's to the low 90's in terms of days. Is that a trend that you expect to continue to lengthen, or do you think that is plus or minus 90 frac days is going to be more of the standard?

Ron, this is Mack. We want that to come down, obviously. It creeped up for a couple of reasons. One, I described earlier. The vendors pulled frac dates because they needed additional time for their maintenance. 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.

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. So, that was - - we contributed to that problem by using those two wells for that reason, but we want to - - 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 are just stacked up a little bit on the frac dates and we're working hard with the vendors to rectify that and I think we can. So I think that spud to sales time will some back down.

Okay. Then the second question will be, 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. Is that still - - are those two issues baked into your ending frac set target?

Ron, the two major vendors for fracing are Haliburton and B.J., and or course we are working with the others as well.

Okay.

And Ron, on your question on production, I think that we have enough conservatism in the production to count for the longer times to bring the wells to sales and maybe some of the reduced choke production scenarios. I think that it - - the transition from some of those items from the quarter before where we had short connect times because 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 high as a decline rate, either. But overall, if we keep our drilling budget intact and the seven rigs busy, we feel good that we will have the production growth we promised in our guidance.

Our next question will come from the line of Richard Tullis with Capital One Southcoast. Please proceed.

Good morning. Thank you. 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 (inaudible), 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.

Right. 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 is pretty early in the life of the well. So we are going to have to defer to answer that question later. And the drilling complete on that well, which was drilled earlier in the year was about $8 million.

$8 million. Okay. I think that is all I had. Appreciate it.

Sure. Thank you, Richard.

And our next question will come from the line of Kim Pacanovsky with NLV. Please proceed.

Good morning, gentlemen.

Hi, Kim.

Hi. A couple of questions. I will keep it to two since it has been a long call. 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 is you are drilling?

That is a great question and the short answer is sure. We have the flexibility to do that, and as a 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.

Okay. Great. And with all of - - 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, we planned well ahead for our proppant needs, so we think 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.

Okay. Great. I will ask you the other things offline. Thank you.

Thank you, Kim.

And our next question will come from the line of Jeff Robertson of Barclays Capital. Please proceed.

Thanks, Mack. I apologize if you've already answered this. I missed a little bit of the call. But can you talk a little about the cost of the wells with the new completion designs you all are using. And secondly, can you talk a little about the geologic differences in the shale between the North Toledo Bend and South Toledo Bend in Logansport where based on slide 24 it looks like you've got a little bit lower IP's in North Toledo Bend.

Sure. Jeff, the costs are being impacted by the increased demand for high pressure pumping services in the Haynesville as well as other shale plays in the region. So, the drilling complete costs have certainly come up from third quarter last year where we were - - we had drilling and complete costs 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 pressure pumping services providers taking a step back from the 24 hour operations and going to daylight operations only so they can provide some time for equipment maintenance.

There is also some equipment redesign work going on their pumps, but I won't get into that. They have had problems on the foot ends and getting deliveries from their manufactures on the foot ends to replace those that are damaged beyond repair has created a bit of a problem in getting equipment back into service. So all of those things add up to increased completion costs. The drilling costs have stayed pretty much the same. Most of the increases that we have seen are on the completion side. Your question about the geological differences between Toledo Bend North and South and Logansport. We find the porosity and reservoir thickness, and shale, 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 reservoir development as you go south.

We find that the upper is also prevalent across Logansport, and Toledo Bend North and Toledo Bend South, it is very good at the southern location. Clay content is another key, it's a highly variable attribute in the play. You can see that especially on the Texas side, stretching into the Louisiana side. And what the operators are doing to address that are finding different ways to complete the wells with specialty products that provide enhanced performance in those zones that have a higher clay content.

But certainly, in order to get maximum fractures developed, when you treat the well, you would like the shale to be more brittle, just to keep it simple here. And in some places in the play, the shale is more elastic and as a consequence, you are not able to get a good fracture network developed from your pumping of the frac stages. So, the increased number of stages is certainly helpful to handle that problem or address that problem. We have some operators who are pumping over 20 stages.

There has been an indication that one operator pumped 28 stages. The bottom line though, there has to be a cost effective optimum, and that is yet to be determined in any of the above examples. So, that is where we benefit from our relationships with certain other operators trading data and getting information across the board so we can arrive hopefully at the optimum solution faster than we would otherwise.

Okay. Thanks, Mack.

Sure, Jeff.

Thank you, Jeff.

Our next question will come from the line of Dan McSpirit with BMO Capital Markets. Please proceed.

Gentlemen, good morning. Thank you for taking my questions. You speak to reserve growth this year, or at least what is estimated, 400 to 500 Bcfe this year. One, can you shed some light on the PDP and PUD components of that and 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?

Dan, this is Mack. The 400 Bcfe to 500 Bcfe, as far as the split between the PDP and PUDs, we are only assigning two offset PUDs to every PDP. So in all the wells we are drilling this year set up two offset PUDs. There are no cases that doesn't, if there are, there may be one or two that don't set up the two PUDs. So that is the distribution on the reserve question.

On the upside, still unknown, because we're evaluating the improvements that we are gaining through the 18 stages, and versus 12 or 14 stages in the earlier completions, as well as increased proppantt 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 the EUR. And of course that data, like I mentioned earlier in the call, that we have a lot of data supportive of that conclusion. We need to get our own wells data set that we can use for comparison purposes to support those improved EUR's. So that is upside.

Got it. Thank you. And one last one if I may. 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 the Company, 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 think you have known us for a long, long time. I would tell you that one, we demonstrate we care where the stock price is because we haven'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 the Haynesville wells, but we're not drilling these wells to hold acreage. We really are drilling them because it is a G&G play. It is not some company that we bought and we're drilling development wells. We're still trying to 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 had 13 million, 14 million per day production, 54 plus Bcfe in reserves, which is San Juan, which is Mid Con and then the Laurel, Mississippi area. 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 have somewhere north of $200 million to either 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, so I mean we are always looking at new areas to compliment our existing area. But, I think right now our goal is to prove this up. If we need to pull a rig in June, August or November, we will do that.

One thing that the market wanted us to do in 2008 was to drill more Haynesville wells and we decided not to do that because it was emerging. We didn't issue shares to buy leases and drill wells and stuff. We just kind of hung on to what we were doing and we drilled a bunch of vertical wells. We had a phenomenal year. I think we are positioned as a management group to continue to do that in 2010.

We are looking at these other plays, and I think if it - - if one of those pitches comes across the plate and we want to swing at it, then we might do that. But I don't think you swing at every pitch that comes across the plate because there is a consequence for every swing you make. So we are going to be disciplined. Hopefully, that is why you and others, and in particularly the stockholders. You know what our personalities are like, Dan, and you trust that we will continue to create value. I know it's painful when gas prices are so low. I understand that. But it could certainly be a lot more painful if we didn't have a balance sheet to do what we are doing. I hope that answers your question.

It does, Jay. I appreciate the response. Thank you.

Ladies and gentlemen, that is all the time 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 my closing remarks. We did have a really great quarter. We continue to keep our strong balance sheet. We starting proving up Toledo Bend South which there were a bunch of naysayers out there that thought we may not like Toledo Bend South, but we do. I do think that if we continue to focus on reserve growth this year, we will have production growth, but reserve growth is equally as important.

We don't see any point in time where we have to access the capital markets, and our risk/reward profile really is not altered. The costs have gone up a little bit but our EUR's will continue to go up. So with that I thank you for the hour or so that you've spent. I know it is a busy morning and we are always thankful for your participation and ownership with the Company. Thank you.

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