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Executives

Jay Allison – Chairman, President and CEO

Roland Burns – SVP and CFO

Mack Good – VP, Operations

Analysts

John Freeman – Raymond James

Brian Corales – Howard Weil

Jack Aydin – Keybanc Capital Markets

Ron Mills – Johnson Rice and Company

Mark Qiu – Credit Suisse

Leo Mariani – RBC Capital Markets

Amir Arif – Stifel Nicolaus

Kim Pacanovsky – MLV

Michael Bodino – Global Hunter Securities

Dan McSpirit – BMO Capital Markets

Richard Tullis – Capital One Southcoast

Ray Deacon – Pritchard Capital Partners

Noel Parks – Ladenburg Thalmann

Comstock Resources, Inc. (CRK) Q2 2010 Earnings Conference Call August 3, 2010 10:00 AM ET

Operator

Good day, ladies and gentlemen, and welcome to the Comstock Resources’ Second Quarter 2010 Earnings Conference Call. (Operator Instructions) As a reminder this conference is being recorded for replay purposes.

At this time, I would now like to turn the call over to Mr. Jay Allison, Chairman and CEO. Please proceed sir.

Jay Allison

Welcome to the Comstock Resources’ second 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 a presentation entitled Second 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 second quarter financial and operating results as well as updated 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. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct.

Now if you would refer to Page 3 of the presentation where we summarize the second quarter results; strong production growth and higher oil and gas prices improved our financial results in the second quarter compared to the second quarter of 2009. Our production in the second quarter increased 30% to 20 Bcfe. For the quarter we reported revenues of $91 million, generated EBITDAX of $63 million and net operating cash flow of $56 million, or $1.23 per share.

We had a small net loss in the quarter of $1.6 million or $0.04 per share. We continue to have strong results in our Haynesville Shale drilling program; 47% of our companywide production is now coming from the Haynesville Shale. We drilled 36 successful wells, including 34 horizontal Haynesville Shale wells in the first half of this year. We’re on track to 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 upon the capital markets for any funding.

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

Roland Burns

Thanks, Jay. On slide four in the presentation we break out our production by quarter and by each operating region and we highlight the production from our Haynesville Shale wells in red on the chart.

For the second quarter this year, our production averaged 219 million cubic feet of natural gas equivalent per day, 30% higher than our production in the second quarter of 2009 of 169 million per day. Production was also up for our first quarter average rate of 209 million per day. Our East Texas/North Louisiana region averaged to 160 million per day with 58 million coming from our Cotton Valley wells and 102 coming from our Haynesville Shale wells.

Haynesville wells are now making up 47% of our total rate. Our South Texas region averaged 44 million per day and our other regions averaged 15 million per day in the quarter.

We had some ownership adjustments which added some production to the East Texas/North Louisiana region in this quarter. Starting in the second quarter, we’re running behind in completing our Haynesville Shale wells due to the unavailability of pressure pumping services. We currently have 17 Haynesville Shale wells drilled, waiting on completion and the backlog continues to grow.

Given this situation, we’re lowering our production guidance for this year. We expect production in 2010 to approximate 74 Bcfe to 77 Bcfe, which represents a 13% to 18% growth over 2009. We do expect production in the third quarter to decline from our second quarter record-high level.

Oil continued to be strong this quarter as shown in slide five. Our realized oil price increased to 37% in the second quarter of 2010 to $67.37 per barrel as compared to $49.24 per barrel in the second quarter 2009. For the first half of this year our average oil price was $67.24, 60% higher than our average oil price of $41.95 for the same period in 2009. Our realized oil price has averaged to 86% of the average benchmark NYMEX WTL price so far this year.

Slide six shows our average natural gas prices. Our average gas price increased 5% in the first quarter to $4.09 per Mcf as compared to $3.88 in the second quarter of 2009. For the first six months of this year, our average gas price increased 9% to $4.68 per Mcf as compared to $4.30 per Mcf for the same period in 2009. Our realized gas prices averaged to right at the NYMEX Henry-Hub gas price so far in 2010. We did have 12% of our gas production hedged in 2009 and none of our productions hedged this year.

On slide seven, we cover our oil and gas sales, the improved oil and gas prices combined with the 30% production increase caused ourselves to grow by 40% this quarter to $91 million. For the first six months of this year, our sales increased 48% to $197 million as compared to $133 million for the same period in 2009. Our earnings before interest, taxes, depreciation, amortization, and expiration expense and other non-cash expenses, or EBITDAX grew by 49% to $63 million as shown on Slide eight. For the six months ended June 30, 2010, EBITDAX increased 64% to $143 million.

On slide nine, we cover our operating cash flow, and our operating cash flow for the quarter came in at $56 million, a 33% increase as compared to cash flow of $42 million in 2009 second quarter. For the first half of this year, operating cash flow was $128 million, 47% higher than cash flow of $87 million for the same period in 2009.

On slide 10, we outline our earnings, we reported a net loss of $1.6 million or $0.04 per share, compared to a net loss of $11.5 million or $0.26 per share in 2009 second quarter. Improvement in the financial results comes from the improved oil and gas prices and the production growth.

Our second quarter results included a gain from the sale of assets of $4.9 million, which primarily relates to our sales of 520,000 shares of Stone Energy which we sold in April. For the first half of this year, we reported net income of $5.7 million or $0.12 per share as compared to net loss for the first half of this year of $17.1 million or $0.38 per share.

On slide 11 we show our lifting cost per Mcfe produced by quarter. We’ve broken out our lifting cost into three components, production taxes, transportation and then other field level operating cost. With our increasing Haynesville Shale production, we are transporting more of our gas to the long haul pipelines rather than selling the gas at the well head. It resulted in an increase in our lifting cost, but this is being offset by improved gas price renovations, as was shown this by our average gas price realization approximating the NYMEX Henry-Hub price this year.

We have reclassed all our prior period data to be consistent with this presentation.

Our total lifting cost averaged to $1.13 per Mcfe produced in the second quarter 2010 as compared to $1.14 in the second quarter of 2009 and $1.08 in the first quarter of this year.

Production taxes increased this quarter to $0.24 and this quarter we didn’t receive any refunds for some of the type gas credits that we received in most of the quarters before this. Transportation cost averaged $0.18 in the second quarter and our field operating cost averaged $0.71 this quarter as compared to $0.89 in the second quarter of 2009. The improvement is due to the higher production level as many of these costs in the field are fixed in nature.

On slide 12, we show our cash, G&A per Mcfe produced by quarter, which excludes the stock-based compensation. Our general and administrative cost decreased to $0.27 per Mcfe produced in the second quarter 2010 as compared to $0.34 in the second quarter 2009 and $0.30 in this year’s first quarter. The improvement is mainly due to our higher production level.

Our depreciation, depletion and amortization per Mcfe produced is shown on slide 13. Our DD&A rate in the second quarter averaged $2.87 per Mcfe, an improvement from our $3.31 rate in the second quarter of 2009. Our DD&A rate this quarter also decreased $0.28 from the $3.15 that we had in the first quarter. With Haynesville Shale production continuing to increase as a percentage of our total production, we’re seeing our reserves grow and this is also the result of this lowering our DD&A rate.

On slide 14, we detail our capital expenditures for the first half of this year. We spent $118 million for a drilling program this year, as compared to $167 million that we spent for the same period in 2009. We spent most of that, $178 million, in our East Texas/North Louisiana region with only $4 million spent on our other properties in South Texas and the other regions.

In addition to the drilling expenditures we made this year, we also spent $62 million this year to acquire exploratory acreage. $39 million was spent to acquire 5,000 additional net acres respective for the Haynesville and Bossier Shale in North Louisiana, and we also spent $23 million to acquire 8,000 net acres in the emerging Eagle Ford Shale in South Texas.

Slide 15 presents our capital structure at the end of the second quarter. On June 30, we had $43 million in cash on the balance sheet and we had $54 million in marketable securities representing the shares of Stone Energy. We had a total of $468 million of total debt, which is comprised of $117 million of our 6 and 7/8 percent senior notes and $296 million of our 8 and 3/8 percent senior notes. We did repurchase 3 million of our 6 and 7/8 percent notes at just under par in the second quarter.

We have nothing outstanding under our buy credit facility, which has an unused borrowing base of $500 million. Our book equity at the end of the quarter was at $1.1 billion, making our net debt only 24% of our total capitalization.

We expect to fund our drilling expenditures and acreage purchases that we budgeted for this year with our cash flow, our cash on hand and the proceeds from asset sales. By the end of the year, we do not expect to have increased our debt balance at any significant way, and certainly we have no plans to sell any equity this year to raise capital.

I will now turn it back over to Jay.

Jay Allison

Thank you, Roland. That’s excellent report. On slide 16, we focus on our East Texas/North Louisiana region. Our activity in this region is focused on developing our Haynesville and Bossier Shale properties. We drilled 35 wells in this region in seven different fields in the first half of this year. All of these wells were successful. 34 of these wells were horizontal wells. We have tested these wells at a per well average rate of $11.3 million per day. The horizontal wells averaged 12.1 million per day and the operated Haynesville wells average 12.5 million per day. Since our last operational update, we’ve completed five operated Haynesville Shale wells. Three of the completed wells are in our North Toledo Bend field in DeSoto Parish Louisiana; one is in Logansport Field in DeSoto Parish and one in the Beckville field in Harrison County, Texas.

The wells North Toledo Bend were tested, at an average per well initial production rate of 10 million per day. The Logansport well was tested at 16 million per day and the Beckville well in East Texas was tested at 9 million per day. These wells were drilled with horizontal laterals from 4500 to 5000 feet and were completed with 15 to 18 frac stages. The initial production rates reflect our choke back program where new completions are being tested and produced with a tighter choke to maintain a high reservoir pressure and the well for a longer time. We believe that the ultimate reserve recovery will improve when the well’s completed in this manner.

On slide 17, we recap our holdings in the Haynesville Shale play in North Louisiana and East Texas, which is updated for additional 5,000 net acres we acquired this year. Our acreage is highlighted in blue. We currently have 89,000 gross acres and 78,000 net acres that we believe are prospective for Haynesville Shale development; 56,000 acres are in North Louisiana, the better part of the play in our opinion. Given expected well spacing of 80 acres and expected pro-well recovery of 5 Bcfe per well, our acreage could have 3.7 Tcfe of reserve potential.

Turning to slide 18, you see the acreage that we think also has potential for the development of the upper Haynesville shale and middle Bossier Shale. Our acreage is highlighted in blue. We currently have 60,000 gross acres and 50,000 net acres that we believe are prospective. Given similar expected well spacing of 80 acres and an expected per well recovery of 5 Bcfe per well, our acreage could have 2.3 Tcfe of reserve potential.

I will now let Mack Good make a few comments on our operations in the Haynesville Shale. Mack?

Mack Good

Thanks, Jay. Good morning, everybody. Slide 19 will show you the number of days it’s taken to drill 59 operated horizontal Haynesville wells that we’ve drilled to date. On the slide you’ll see that our average drill time for all of these wells is 40 days. The average drill time for our first five well drilled, of the 59 wells, was 50 days, compared to 33 days for our last five wells. Our shortest drill time to date is 25 days to TD. Obviously, we’ve improved our drilling performance considerably since our initial drilling operations in the play.

On slide 20, we show the number of days it’s taken to connect each of our 44 operated horizontal wells in the Haynesville that are currently flowing to sales. Comstock’s average connection time to sales is about 100 days, for all 44 wells currently flowing to sales. Our average days from spud to sales for our first five wells was 129 days compared to 104 days for our last five wells. Last year, as you recall, the lack of pipeline infrastructure was the major factor contributing to the time that it took us to connect the well to sales. We overcame most of the infrastructure issues and reduced the time frame to connect the sales down to as low as 60 days.

However, starting in the second quarter this year, we began to experience delays in getting the wells completed. Shorter drill times, larger frac jobs, sizes, that all of the operators are pumping as well as the increased rig count, and the region created very high demand for high-pressure pumping services. And as a result, we now have 17 drilled Haynesville or Bossier shale wells that are waiting on a frac completion.

We’re currently negotiating with several of the major service companies to gain exclusive access to some of the new crews and equipment that they plan to put on service late this year or early next year, which will allow us to catch up with our drilling completion inventory. We expect our completion backlog to continue to grow through the third quarter, and not start to improve significantly until later this year.

Slide 21 outlines our planned activity this year to further develop our Haynesville and Bossier Shale acreage. 41 wells are planned for Logansport and 15 are planned for Toledo Bend North and South field. Most of these wells will target the lower Haynesville Shale but we do plan to drill up to 15 upper Haynesville Shale or Bossier Shale wells this year. We plan to move one of our seven operated rigs out of our Haynesville operations to our new acreage in the Eagle Ford late in the third quarter. Given the efficient drill times we are achieving, we will still drill all the wells we had originally budgeted for our program, even with this rig leaving early to the Eagle Ford.

Our South Texas region is displayed on Slide 22. We drilled one well in this region in the first quarter. The Julian Pasture number 4 was drilled in our Ball Ranch field and was tested at an initial production rate of 8 million a day in the second quarter.

Now I’ll turn the call back over to Jay to go over our plans to expand on our operations in the emerging Eagle Ford play.

Jay Allison

Thank you, Mack. I’m sure they’ll have some questions in a moment. On slide 23, we present our acreage footprint in the Eagle Ford shale in South Texas. We have acquired or in the process of closing on 18,000 net acres that we feel are prospective for development in the emerging Eagle Ford Shale play in Karnes, McMullen, and Atascosa counties in South Texas. We’re focusing primarily on the oil and condensate windows in this play due to the better economics of oil versus natural gas. We hope to acquire additional 10,000 net acres in our focus area. Given expected well spacing of 80,000 acres and an expected per well recovery of 400,000 barrels of oil per well, our acreage could have 67 million barrels of oil equivalent of reserve potential. As Mack said earlier, we plan to move one of our Haynesville rigs to this region and expect to drill three Eagle Ford Shale wells on our acreage by the end of this year.

In 2011 after we have completed our leasing activities, we plan to have a two to three rig program to develop our Eagle Ford Shale acreage.

On slide 24, we outline what we expect to spend this year on our drilling program and on our acreage acquisitions. Our drilling expenditures are down from our earlier estimate even though we are drilling more wells. With the shortage of completion services, we will carry a number of drilled wells over into 2011 for completion, which delays those expenditures until 2011.

We expect to spend $350 million for our drilling program to drill 69 wells, 66 are horizontal wells, 63 are in the Haynesville or Bossier Shale and three are in the Eagle Ford Shale. We are budgeting $150 million for our acreage acquisitions, we expect to spend $46 million on Haynesville leases and $104 million to establish our position in Eagle Ford Shale in 2010.

In summary, I would ask that each of you refer to slide 25, we continue to be excited about our prospects for reserve growth this year. Despite the weak natural gas prices and the completion delays we are experiencing, we are still very well positioned to have substantial reserve growth at a very low finding cost. Our 2010 drilling program estimated to cost $350 million will focus almost primarily on developing our Haynesville Shale acreage. We think our Haynesville Shale program could add 400 to 500 Bcfe of proved reserves in 2010.

With pressure pumping services hard to obtain, we have had to trail back our expectations for production growth, instead of having 18% to 25% production growth this year in our Haynesville Shale program, our production growth will fall in the range of 13% to 18%. This production is not being lost, it is just being deferred into 2011. Our recent leasing efforts have given us a foothold in the emerging Eagle Ford Shale in South Texas. Our goal is to lease up to 25,000 net acres in the oil and condensate windows of this play.

We are maintaining growing our inventory of drilling locations and have a large inventory in the upper and lower Haynesville Shale and Cotton Valley in East Texas in Louisiana and then the Eagle Ford, Vicksburg and Wilcox trends in South Texas.

We continue to maintain a very strong balance sheet. We have $500 million available on our completely unused bank credit facility. We plan to use the proceeds from our Mississippi asset divestiture which is being marketed to help pay for our acreage acquisitions this year. We plan to fund all of the estimated $500 million expenditures this year with cash flow, cash on hand and the proceeds from non-core asset sales.

For the rest of this call, we 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 question. If you have additional questions that remain unanswered, please feel free to queue up again for a follow-up question.

Anita, I will turn it back over to you.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of John Freeman with Raymond James.

John Freeman – Raymond James

My first question has to do with the CapEx budget. Obviously, you all got a lot more flexibility than most in the Haynesville. I believe in the past you said you have only got to drill like three or four wells, the remainder of this to sort of hold the acreage there. There was going to be a pretty hard look at the budget in June, I believe you all said in your last call because that was when the first of three of your seven rigs were due to roll off contract. I think there was on in June, one in August, then one in November. And I am just sort of curious about what sort of took place and when you look at the budget, I assume you decide to keep the rig in June, came off contract and then sort of plans going forward and if there is still an opportunity to maybe lower the drilling part of the capital further.

Mack Good

This is Mack. Yes, we are evaluating that as we go. Obviously, we are stockpiling completions. We are reviewing the economics of the Eagle Ford versus the Haynesville. As Jay mentioned earlier, we are discussing here about the go-forward plans for the Eagle Ford that we move one or two rigs early on in our entry into the drilling ops in Eagle Ford. So that will determine whether or not we release one of the seven rigs or send it, rather than releasing it send it to the Eagle Ford.

John Freeman – Raymond James

And one that was I guess renewed in June, can you give me what the terms of that was versus what it was on contract at?

Mack Good

We are well to well with that rig.

John Freeman – Raymond James

Oh, you are, okay. And then last question I had, I will turn over to somebody else, just on the completion side in terms of, you are currently sort of negotiating with various service providers. Is the thought that you sort of do, sort of a term contract where you have got guaranteed days assigned to you?

Mack Good

Yes. That crew, the frac equipment and the crew would be a dedicated service crew for Comstock wells only.

Jay Allison

I think what will probably happen is we will evaluate since we picked up right at the 18,000 net acres in Eagle Ford well, see whether we will move one or two rigs over like Mack had said, and the rig that rolled off in June is well to well and the one in August, if we keep it will go well to well. So really I would think that in November would be our next really decision point and see whether we keep that rig or we move it over to the Eagle Ford.

Operator

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

Brian Corales – Howard Weil

Just a follow-up on the completion side. Are you also talking about locking up some dates with the Eagle Ford as well because I know that the area has pretty tight?

Mack Good

Absolutely, you bet.

Brian Corales – Howard Weil

Okay. And then in terms of the Eagle Ford cost, is there a lot of additional running room there to add to that acreage position and what are you seeing in terms of leasehold costs?

Mack Good

Leasehold costs are varying across the play as you might expect. We are not going to pay some of the implied run up prices that I am sure you know about. We don’t think that’s appropriate at this point of play. And so, just as we follow the approach in Haynesville, we are targeting leasehold in the range of 2000 to 5000 an acre as a maximum and we are accruing our acreage on that basis. There is some running room in the play at varying risk levels. Of course, we are targeting some specific regions just as we did in Haynesville following the same kind of strategy where we want multiple footprints. And as Jay mentioned earlier, we are targeting the oil and condensate windows for the leasehold efforts that we are making.

So we want contagious developable acreage where we can drill our laterals in the orientation that we prefer. And so that also enters into the equation.

Jay Allison

We started looking at the Eagle Ford probably a year ago, started leasing this year. We have been invited to participate in acreage packages of 20,000, 30,000, 40,000, 50,000 plus. And what we have done like Mack said, we entered this region the same way we did the Haynesville. We said we are really not willing to pay up, we want to operate and we really right now we think that the Karnes, McMullen, and Atascosa area is the best area for us to be in. We will test those three counties and we will do that exact same way we have developed our wealth in the Haynesville. And I think as far as the cost to get in that acreage, remembering ‘08, we sold some non-core gas properties on shore for $136 million and we took those dollars when we use those to add to our Haynesville footprint and hopefully that’s what we do in 2010 with the sale of the package that we have right now in Mississippi which is mainly oil.

We take those dollars and then our free cash flow and then cash in the bank and that’s how we would enter this Eagle Ford area with again about 25,000 net acres, which I think is a good start for us.

Operator

Your next question comes from the line of Jack Aydin with Keybanc.

Jack Aydin – Keybanc Capital Markets

I apologize if you addressed this one. Did you guys – last topic, crew, completion and crew in the Haynesville area? I apologize if you went through it.

Mack Good

We are negotiating on that. We feel that an agreement is eminent but we don’t anything to announce today about that.

Jack Aydin – Keybanc Capital Markets

Okay. Now you have about 17 wells in inventory. Going toward the year-end, what do you think, how many wells you might end up having in inventory?

Mack Good

Well, there are some assumptions built into that. Of course, Jack, as you know, I am hopeful that we will be able to reach an agreement with the service provider that will allow us to have access to additional capacity in Y10, that it won’t just be a Y11 solution for a completion backlog. But if so, if it is just a Y11 availability, then we may have a completion backlog approaching 25 wells by the end of the year.

Operator

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

Ron Mills – Johnson Rice and Company

A couple of questions. Obviously, all of the East Texas North Louisiana horizontal wells that were completed in the quarter were in the Haynesville. I know that you have drilled a number of other Bossier wells. What determines the completion of Haynesville versus Bossier? Is it just locations, once you actually got the frac crews on location?

Mack Good

You mean the order that we plan to complete them?

Ron Mills – Johnson Rice and Company

Correct.

Mack Good

We are going to focus on getting the uppers completed, not necessarily first but certainly toward the front end of the operations going forward when we do get the dedicated crew. And that is because we have so many lower Haynesville completions that we have much more data and much more information about performance, reservoir attributes, all of that stuff that we can use in forecasting forward our drilling program, reserve adds, etcetera. So we are going to bring forward the upper Haynesville completions in going forward with the completion plan.

Ron Mills – Johnson Rice and Company

From an industry stand point, what are the discussions on the pressure pumping side in terms of the amount of frac crews that people are looking to add in the region? And then how does that impact Haynesville acreage in terms of held by production? As John said, you had very few wells needed to maintain your 2010, and on a seven rig program, you were probably through 2011. Just curious how these completion delays impact your ability to hold that production and how much capacity additions are expected?

Mack Good

Well, the additional capacity that we have been told will be entering the market in 2011 is a range and it depends upon delivery time of the equipment and what the Haynesville operators do with regard to the use of that equipment. I will mention something about that in a minute.

At least 10 crews or additional crews for the Haynesville are anticipated for 2011. That’s the maximum. And some of those crews, some of those ten (ph) could be sent elsewhere depending upon and by elsewhere I mean the Eagle Ford and the Bakken, depending upon the internal evaluations that each of the service providers are going to go through.

What the operators do matters because if the operators in the Haynesville for example would lower their treatment rights to say 60 barrels per minute from 80 barrels per minute. That would obviously free up additional pumps that would not have to be on location to get to an 80 barrel per minute level, all other things being equal. And those pumps could be used to form another crew if you will.

If a service provider has five crews in the Haynesville and they take 20% of the pumps from each crew will then, they could form another crew. Some operators are looking into that and have actually done that successfully. We are doing some of that as well to see if we can adequately treat our wells at the lower rate. So far we have been pleased with the results, we are pumping in about 65 barrels to 70 barrels a minute and we are looking at the possibility of going even lower and working with the service providers and finding a common solution is good for them. It’s obviously at a lower rate. It’s easier on their equipment, they have lower maintenance cost, which is some of those cost savings would be shared with us.

So hopefully that answers your question on that.

Operator

Your next question comes from the line of Mark Qiu with Credit Suisse.

Mark Qiu – Credit Suisse

I was wondering if you could kind of address, with the full quarter under your belt in restricting rates on wells, how the production profiles have been holding up? And what you think the impact on the EURs might be with some more data?

Mack Good

Well, we are very pleased with the results. If Comstock’s reservoir group manager were here, he would say, “Hey, we need a little more data to form up the EUR forecast.” But certainly on a preliminary basis, we are seeing things that we hope to see. We are seeing a softening in the production decline, we are seeing higher flowing pressure maintenance, which is obviously a good thing. And then with the initial forecast that we have done, we are seeing a 20% to 30% EUR potential improvement.

So we are quite pleased with the results. We think in most places within the Haynesville play, that’s going to be the way to go.

Mark Qiu – Credit Suisse

And then I guess in terms of AFEs on Haynesville wells, where are they currently in? Do you think there is more room to the upside in terms of cost inflation?

Mack Good

That’s a good question. We are seeing cost escalation since the beginning of the year between 20% to 30%. Most of those cost increases have come from increases on the completion side cost with the high demand for high pressure pumping services, that’s the expected. We feel like there is some room for some additional cost inflation, just until the additional equipment gets into the marketplace in 2011 and some of the operational activity subsides, meaning some of the operators will take their foot off the accelerator for various reasons, some can’t and some can. And we think that the driving force obviously is going to be supply of high pressure pumping equipment versus the demand for that equipment.

We have squeezed a lot of cost out of the drilling side. It’s the escalation or inflation on the completion side cost that needs to come down and will come down.

Mark Qiu – Credit Suisse

And then just where AFEs are currently?

Mack Good

AFEs right now are running anywhere from 9 million to 10.5 million per well.

Operator

Your next question comes from the line of Leo Mariani with RBC Capital.

Leo Mariani – RBC Capital Markets

Curious on the production ramp. You guys guided to production down, sequentially, in third quarter. Any further guidance on that as to how much you think it is going to be down roughly in 3Q?

Roland Burns

This is Roland. We do think that the third quarter will probably definitely be down from the very high level on the second quarter. There is some real uncertainty about it, if we some more completions down and then which wells are completions, how much they get to contribute but we are off to a very slow start for the quarter. And we believe it would probably be a little higher probably then the third quarter rate of 2009, but not anywhere near the level we were in the second quarter. I think the fourth quarter, we will see some improvement in the rate and so I think we will start to see and start to get back in the line in the fourth quarter and how much it gets back in line will be determining, if we get some more completions in this year.

So I think overall I would assume that the depth is in the third quarter and then you start to come back in the fourth and then achieve that range that we have kind of put out there for the overall year of 13% to 18%.

Leo Mariani – RBC Capital Markets

Just jumping over to your asset sale, you guys are selling your Mississippi oil property. Any sense of potential timing as to when the cash would come in the door and any other potential asset sales that may happen in the near future?

Roland Burns

On the Mississippi asset sale, that process has been underway and is going very well. We are running a formal bid process and we expect to have the bid then this month and I would suspect that if everything goes well, we could close that asset sale very early in the fourth quarter.

As far as other assets that per se, right now we don’t have any other formal plans to selling other assets this year. I think we will be, as we formulate our 2011 business plan, we will be looking at some of the areas that don’t have activity and other areas that are kind of away from our core East Texas North Louisiana and South Texas regions and then see if it makes sense to divest to some more of those. Lot of those were gas assets. So that’s why we didn’t put those on the market this year and chose to instead to do the heavy oil field in Mississippi and the related production around that in the state of Mississippi.

Operator

Your next question comes from the line of Amir Arif with Stifel Nicolaus.

Amir Arif – Stifel Nicolaus

In the Haynesville, I mean just given that the backlog if anything, will get worse, any thought of maybe cutting the number of wells you’re going to build to bring your cash flow CapEx in line?

Mack Good

Well, in a manner of speaking, that’s what we are doing with the transfer of the rig to the Eagle Ford. Although certainly the Eagle Ford service side is an issue as well and that’s why we are making it part of our discussions with the service provides and providing a dedicated crew. And then, as we mentioned earlier, we are evaluating where or not we should send another rig to the Eagle Ford or release it. So all of those things I am sure we will make a decision by the next conference call.

Amir Arif – Stifel Nicolaus

Just while we’re on the Haynesville, I noticed a shift away from the Toledo Bend drilling toward the Logansport. Can you just provide some colors of the quality of the drilling or just where the rigs are currently?

Mack Good

Well, both. We are also evaluating upper Haynesville in Toledo Bend South. So we needed to move rigs there. The Logansport area is an expensive area. It involves Belle Bower, Bethany Longstreet, Logansport, and as well as another area called Red River Bull Bayou. So we are necessarily drilling a number of leases within the Logansport package. But the upper Haynesville within the Toledo Bend North is something we are going to be targeting going forward for the rest of this year because frankly, we have got almost all of the leases held down through the lower Haynesville already. So we have opportunity to evaluate what appears to be a very good upper Haynesville opportunity in Toledo Bend North.

Amir Arif – Stifel Nicolaus

On the Eagle Ford, I’m just trying to get a sense of drilling commitment. So are you leasing acreage from others who have already leased it? So is there a shorter fuse on acreage expiry or do you have a full three years?

Mack Good

Full three years, yes.

Operator

Your next question comes from the line of Kim Pacanovsky with MLV.

Kim Pacanovsky – MLV

On the Eagle Ford, where will your first location be? I see you have a little bit of the oil window in there, mostly condensate window but where will it be or where will the first three wells be? What are the nearest completions to these first locations?

Mack Good

Well, this is Mack. First well is going to be at McMullen. We are going to be evaluating the exact location obviously that well bore placement, whether it’s in the condensate or deep oil windows. The second well at this point we plan to drill in Atascosa and the third well at this point we plan to move over to Karnes.

There is not a whole lot of offset wells near us in McMullen, although the geological correlations fit very nicely through our acreage tracks in McMullen, we have the EOG wells to the north and northeast and of course, you I am sure follow the EOG press releases on their wells, they are quite happy and they – Atascosa will be playing a little bit off the EOG extrapolation. At Karnes, there is wells that have IPed at over 800 barrels a day oil and 2 million day gas within a three to five mile radius around our Karnes region.

So I think it gives you a little bit of color on that.

Kim Pacanovsky – MLV

Just assuming you do have completion crews in the Eagle Ford, I’m not sure why you wouldn’t shift two rigs over there. What’s the reason you wouldn’t do it? I mean, even if gas prices improved by a dollar, your economics are still better in the Eagle Ford.

Jay Allison

I think we would do that, we are just kind of leaving ourself a little out. (Inaudible) we will do.

Operator

The next question comes from the line of Michael Bodino with Global Hunter Securities.

Michael Bodino – Global Hunter Securities

Just a little follow-up, on the acreage. You picked up some acres in the Haynesville and the Eagle Ford. Could you give us a little more clarity on where the 5,000 acres in the Haynesville was picked up?

Mack Good

Most of the acreage that we picked up is around our Toledo Bend north and Toledo Bend south areas.

Michael Bodino – Global Hunter Securities

Okay. My second question is if you move into a two to three rig program in the Eagle Ford, pending success, does that imply that you would have a reduced four to five rig program in the Haynesville?

Mack Good

Yes, that’s correct.

Michael Bodino – Global Hunter Securities

As part of the presentation you had a 8,000 acres, and the Eagle Ford locked up, and it looks like 10,000 acres is either pending. Relative to the $82 million you have left on your budget for acreage, I take it that implies that you’re pushing to get 20,000 acres for that or as much as you can get or how does that break out?

Jay Allison

Yes, we have got an agreement that’s imminent for the additional acreage. We feel very positive about bringing that in and we have an additional acreage package that we are negotiating on right now that would get us well over the 20,000 mark.

Michael Bodino – Global Hunter Securities

So could be a third quarter event?

Roland Burns

Right, and we have closed some of that acreage already in the third, it just wasn’t in June, it was in July. So I think the – so it’s a combination of all of those, but we feel pretty good about reaching our goals at the limits that we set for how much we will pay for acreage in getting the share because a lot of these deals are just in the due diligence process now.

Operator

Your next question comes from the line of Dan McSpirit with BMO Capital Markets.

Dan McSpirit – BMO Capital Markets

The fact that Comstock is now getting into the oil business or at least the condensate business, what does this move say about the natural gas business? I ask in an effort to get your honest and genuine views on the commodity and the outlook here going forward.

Jay Allison

I would say somebody approached me this morning and said it might be a blessing in disguise, it would push some of our gas production into 2011 and may have a higher natural gas price and I couldn’t disagree with them. I did think we have – we got quite a bit of gas at there. As you know and there is a lot of wells waiting to be fraced. We had thought that we would probably add another unconventional core area that was already within our footprint, which again is the South Texas area, which is the Eagle Ford (inaudible). We chose not to do that by participating with someone who is being highly promoted and not being an operator, we had in fact said we want to operate in. If it takes six or seven or eight months to acquire the acreage that we would like to acquire and it’s a little harder to acquire it but it’s just as good or better, we operate and we would rather do that and that’s why we had the nasty thing in the first quarter. We waited till now.

So you have something meaningful in size. I think one of the other thing we said we would do is, at the beginning of ‘09, we wanted to test the value of the emerging Haynesville and by the end of ‘09, we drilled maybe 33 wells or so. And then we said at the beginning of this year that there were probably 56 wells or so we wanted to drill driven by the geologist and by the reservoir engineers, and that we had to drill all those wells to hold acreage but we needed to figure out what we thought the better acreage was. We have attempted to lease this 5,000 acres in the Haynesville in tier 1. We have attempted to figure out what percent of our acreage is in tier 1 in the Haynesville. And you notice that we have leased some more acreage in Toledo Bend north and south.

So we kind of indirectly answered those questions. But we also said by the end of the third quarter there once the geological growth period Comstock was comfortable with the value of our acreage, that we might start pulling back some of the wells and if we can push them somewhere else. Now at that time we didn’t know whether we would have enough Eagle Ford acreage to move a rig or two over. But we did make sure that in June, August, November, we would have a rig and we could move a rig or two over depending upon the timeframe. And at the same time, we committed to you as an analyst and the stockholder to create real wells on a per share basis with transparency as we grow the company, that transparency is a big word.

I think we gave for you pretty strong numbers in the second quarter except what, it’s not – that we don’t have financial flexibilities, that we have got the premier asset base, we have got a premier resource play. We reduced our drilling and completion CapEx budget by $35 million, in 2010 we added that to acreage that we picked up for $3000 or $4000 in Eagle Ford. We kept out of being in an area that had regulatory overhangs, we are not in any area where there is a regulatory overhang.

We do have a backlog of excellent wells that we would like to complete. I think you will like the results of the wells, the 17 wells that we have not completed. If we had chosen some of those versus the five that we did complete, it would even have a higher production rate. And our guidance at the beginning of this year was what we thought was right, 18% to 25%, we thought we could get the wells drilled.

Right now what you are going to see is we are at the lower end of that guidance, we are 13% to 18%. I don’t know if we will get to 18%. We feel comfortable with 13% and that is not a function of do we have takeaway capacity. It’s not a function of do we have rigs, it’s not a function of a joint venture partner. It’s just a function of completions. And when gas prices started to drop and completion prices go up materially, we said it doesn’t make a lot of sense economically if you are doing a ground up evolution of adding reserves to pay a lot higher price for completion.

So we chose not to do that. I guess it’s great that we have the flexibility that we don’t have to do that. But in saying all of that, and you say, “Well, how did you get into your two core areas now?”, I think we did it the right way. We didn’t dilute you with equity in the last five or so years. And in fact we said that you don’t own Comstock stock because we own Stone shares. And when we said when Stone was high enough, we would divest ourselves of some of that.

We did, on April 15 or so, we sold the 520,000 shares of Stone and that gave us the chance to profitable in the second quarter. And (inaudible) even look at where our gas is located. I mean our average gas price is the NYMEX gas price.

So I think that’s our total attitude, it’s to give you some transparency in a market that, as you said, I mean the natural gas market right now is not good particularly, we are 94% natural gas and not hedged, might be a natural hedge is there, we can’t track some of these wells by year end and we will look even stronger in 2011 and really not give up any of our strength in 2010. And I think you follow this long enough to know those are our true statements.

I don’t if that’s a long way to answer your question.

Dan McSpirit – BMO Capital Markets

As you evaluate the targeted economics of drilling a well in South Texas versus your first core area in East Texas North Louisiana, what gas price do you need to make that a market neutral or a economic neutral result, i.e. at what price Henry-Hub, does that become a situation where or a result where the economic breakeven or the economic limit between the two areas is equal?

Mack Good

We run our internal economics on the Eagle Ford assuming a $4 flat gas price and $70 flat oil price. And we are economically positive within our projected EUR ranges and we are targeting the cost structure now in bringing that into line with our expectations. Our first wells that we plan to drill in the Eagle Ford are going to be more expensive wells because we are going to get a lot of data for subsequent evaluations just as we did in Haynesville. So the first group of wells in each of our footprints are going to be more expensive as a result of that effort.

The exact breakeven, I can’t give you that. I don’t have that in front of me. But we can provide some guidance later on that.

Operator

The next question comes from the line of Richard Tullis with Capital One Southcoast.

Richard Tullis – Capital One Southcoast

Just a couple of follow-ups. I know you have picked up I guess about 5,000 acres in the Haynesville Bossier area so far in Toledo Bend, North and South and you are planning to pick up a little more. Where are you going to target for the additional acreage acquisition?

Mack Good

Well, we have three footprints that we really like and you mentioned two of them and the other is in the regions that I mentioned earlier, the Logansport area, Red River Bayou, San Miguel Bayou areas. Throughout those regions, we think there are some opportunities to add to our acreage.

Richard Tullis – Capital One Southcoast

These are 20%, 25% royalty?

Mack Good

Yes, 25%.

Jay Allison

Correct, their quarter.

Richard Tullis – Capital One Southcoast

Okay. About the same acreage value, 8000 or so or however it worked out?

Mack Good

Yes, it depends on where you are at. But I think between 4000 to 8000 an acre is a good range to use.

Richard Tullis – Capital One Southcoast

Then just jumping over to the Eagle Ford, the additional acreage you’re expecting to pick up near term, I guess it’s about 10,000 more. Are you expecting that to be at the higher end of that range you gave, the 2000 to 5000?

Mack Good

Yes.

Richard Tullis – Capital One Southcoast

And then just overall of the acreage you have acquired so far, how much is actually in the oil window, what percentage?

Mack Good

Boy, I wish I could give you the answer to that.

Richard Tullis – Capital One Southcoast

Based on the math.

Mack Good

Three to six months I will be able to tell you.

Richard Tullis – Capital One Southcoast

Just using the map, you don’t have an approximation?

Mack Good

Probably third.

Operator

Your next question comes from the line of Ray Deacon with Pritchard Capital Partners.

Ray Deacon – Pritchard Capital Partners

I was just curious, it sounds like you’re not changing the amount of reserve bookings you see in the Haynesville. So I am assuming you believe you’re still going to be able to get as many wells completed by year-end as you had been previously or does the EUR change due to longer laterals and choking back the well some, I guess?

Mack Good

I don’t think it’s fair to ask an eight-part question here. That’s pretty smart move. The bottom line is we haven’t changed our EUR guidance on our Haynesville wells. And reserve additions with the new SEC reserve rules are still online with what we have previously put out because despite the fact that we have not completed the well, we certainly have all of the offset data that supports a reserve add for not only the well drilled but the two offset puds. And we have reviewed this particular issue with several audit groups, given the geological data that we have in house, and then it’s already in the public domain. So we feel pretty comfortable staying with our original guidance on that.

Ray Deacon – Pritchard Capital Partners

I listened to the Pioneer call last week, and they talked about a one-year payout on a frac crew they were purchasing in the Eagle Ford, and I guess I don’t know, would that make any sense to you? Have you ever –

Jay Allison

There is rig shortage, we didn’t buy any rigs, there is a frac shortage, we didn’t buy any frac crews. I don’t know that we are in that business, the service business. I mean if Mack wants to push that management decision and then we would decide that, but right now like we just said we are not in the service business.

Operator

Your final question comes from the line of Noel Parks with Ladenburg Thalmann.

Noel Parks – Ladenburg Thalmann

Of your Eagle Ford acreage, is there any of it that’s held by production, that has (inaudible) production on it?

Mack Good

No, all new leases.

Roland Burns

All new primary leases.

Noel Parks – Ladenburg Thalmann

Okay. And three-year, typically, or –

Mack Good

Yes.

Noel Parks – Ladenburg Thalmann

I guess my other big one has to do with the negotiating with the service companies to get access. Just curious you said that you thought a deal might be happening fairly soon on that. How tricky has it been to arrange to just get the frac crew access without getting a lot of other bundled services in there?

Mack Good

Well, it’s not necessarily the case that we wouldn’t want to bundle services. I mean we use the primary service companies anyway on a number of way of seven rigs running. And we have a number of those services already on our wells. So it’s an advantage really for both parties to have an integrated service package as part of the discussion for a dedicated crew. And there is also a side benefit to that when you do have such bundled operations standby time for equipment, is less of an issue if a problem occurs on location as a consequence of equipment failure. So you are not charged the go-forward standby time. So a little bit of detail. But that’s a benefit of having a bundled service operation.

Noel Parks – Ladenburg Thalmann

And just to clarify, so would you say that you’re at a point where you’re not extremely worried about exactly, who for example does your wire line logging in your new Haynesville wells from here on?

Mack Good

Well, I am always worried about wire line operation, our Haynesville operation. I am not going to say that I am not concerned about that. As part of our negotiations, service quality is part of the negotiated package. And no matter who is on location doing the wireline work in the other services, it’s key to have quality service and the service providers certainly know that. There is some that are better than others at certain times. And so, we address each of those issues individually.

Operator

At this time there are no further questions. I would now like to turn the call back over to Mr. Jay Allison for closing remarks.

Jay Allison

I think those were excellent questions and hopefully we delivered the tight quarter that you were looking for and with the exception of that frac dates in the future, I guess at the end of the day you have to see where your assets are located, have to see how you got there, you have to see what kind of flexibility you have both with your balance sheet and operationally. And then at the bottom line, you have to read the low cost producer and I do think that of all E&P companies, we are at the lower end of cost. So we will continue to try to stay at that place and be transparent as we grow the company. Again, I thank each of you for participating in the call.

Operator

Ladies and gentlemen, this concludes the presentation. You may now disconnect. Thank you and have a great day.

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THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

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Source: Comstock Resources, Inc. Q2 2010 Earnings Call Transcript
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