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Comstock Resources, Inc. (NYSE:CRK)

Q3 2008 Earnings Call Transcript

November 4, 2008, 10:30 am ET

Executives

Jay Allison – Chairman, President and CEO

Roland Burns – SVP and CFO

Mack Good – COO

Analysts

Wayne Andrews – Raymond James

Ron Mills – Johnson Rice

Kim Pacanovsky – Collins Stewart Llc

David Snow – Energy Equities

Dan McSpirit – BMO Capital Markets

Operator

Good day, ladies and gentlemen, and welcome to the Q3 2008 Comstock Resources, Inc.’s earnings conference call. My name is Becky, and I will be your coordinator for today. At this time, all participants are in a listen-only mode. We will be facilitating a question-and-answer session towards the end of this conference. (Operator instructions) As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the presentation over to your host for today’s call, Mr. Jay Allison, Chairman and President. You may proceed.

Jay Allison

Thanks, Becky. Thank you for the introduction. Hello, everyone. Welcome to the Comstock Resources 2008 third quarter financial and operating results conference call. You can view a slide presentation during or after this call by going to our Web site at www.comstockresources.com, and clicking Presentations. There you will find a presentation entitled Third Quarter 2008 Results.

I am Jay Allison, President of Comstock. And with me this morning is Roland Burns, our Chief Financial Officer; and Mack Good, our Chief Operating Officer. During this call, we will review our 2008 third quarter financial and operating results as well as the results to date of our 2008 drilling program.

Our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct.

If you’re following this on the slides, on slide two, I want to make a comment before we go over the third quarter 2008 highlights. I want to make sure that our record setting financial results in the third quarter of 2008, which are – they’re just phenomenal. I mean oil and gas sales of $164 million, EBITDAX of $139 million, cash flow from operations $133 million, continuing net income $55 million, and total net income of $225 million, which is not a gain from a derivative story. It’s actual gain of increased production onshore and the sale of a successful company. I want to make sure that that doesn’t deter you today from voting. It is election day.

When I read these numbers, realizing that Comstock has only about $1.8 billion in assets, I just shook my head and hit the numbers. They were phenomenal. I was driving to work this morning, I thought, “Well, what’s it like?” And I thought, it’s kind of like asking Santa for a red schwin back [ph] for Christmas and receiving that back plus one for every shareholder, which there are 45 million shareholders. I mean quarters like this make everybody happy.

It is a really good story. Now with that, I’m going to go back to the script.

We are very pleased to be able to report our most profitable quarter in our corporate history, this quarter, resulting from strong operating results. And the profit we recognized from our creation of Bois d'Arc Energy in 2004. We are also very pleased to have the company so well positioned in this time when credit and capital are difficult to obtain.

For the third quarter, we reported revenues of $164 million, and we generated EBITDAX of $139 million, and operating cash flow of $133 million. Our net income from our continuing onshore exceeded expectations coming in at $55 million or $1.20 per share. Including the contribution from our discontinued offshore operations of $170 million, we reported total net income $225 million this quarter, or $4.91 per share. $158 million from the discontinued operations represents the after tax gain on the sale of our stake in Bois d'Arc Energy, which closed on August the 28th.

The strong financial results in this quarter were driven by 23% production growth and strong oil and gas actual gas prices in the quarter. The production growth is primarily coming from our successful drilling activities this year. 110 of the 112 total wells that we drilled were successful. We are funding our $425 million in estimated capital expenditures, exclusively out of operating cash flow this year. I am not aware of another E&P company that has been able to match our production rate that has funded all of their CapEx with operating cash flow.

$109 million of our expenditures have been invested to increase our lease-hold in the emerging Haynesville shale play. We have increased our holdings through over 70,000 net acres in this place so far this year, and have four horizontal wells underway to begin developing this significant resource potential.

In hindsight, our best move this year was to complete the divestiture of our offshore operations and the $138 million in non-core properties prior to the onset of two hurricanes, the substantial decline in oil and gas prices, and the current credit crisis that we are experiencing. We are now positioned with a very strong balance sheet, including an undrawn $590 million credit facility that was just reaffirmed by our bank group last week.

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

Roland Burns

Thanks, Jay. Our outstanding financial result for this year from our continuing onshore operations are being driven by our strong production growth, which is shown on slide three. In the third quarter of 2008, our production averaged 163 million cubic feet equivalent per day, which was 23% higher than our production in the third quarter of 2007.

Our production for the first three quarters of this year was 36% higher than production in the same period last year. Production is down slightly from our second quarter rate of 168 million cubic feet per day. These are the 9 million cubic feet of production that we sold at the end of the second quarter. Our successful drilling activities and the South Texas acquisition that we completed at the end of 2007 account for the increase.

On slide three, we break out our production into our operating regions, and then we also separate out the properties that we sold. Our East Texas/North Louisiana region averaged 87 million per day, which is 32% higher than it was in the third quarter of last year. Production in our South Texas region was up 64% to 59 million per day, as compared to the 36 million per day that we had in the third quarter of 2007. Production in our regions was 17 million, which is down from the 20 million a day in 2007. We expect to produce around 59 Bcfe to 60 Bcfe in total in 2008, which will represent a 30% to 33% growth in production over 2007.

Also contributing to the strong financial results were the very strong oil and gas prices that we had in the third quarter. On slide four, we cover our oil prices. Our average oil price increased 64% in the third quarter of 2008 to $105.15 per barrel, as compared to $64.06 per barrel in the third quarter of 2007. Our oil price in the third quarter averaged 89% of the average NYMEX WTI price in the quarter.

For the first nine months of this year, our realized oil price was $97.74, which was 74% higher than our oil price of $56.15 in the first nine months of 2007. For this period, our average oil price was 86% of the average NYMEX WTI price.

Slide five shows our average natural gas prices. Our average gas price increased 62% in the third quarter to $10.16 per Mcf, as compared to $6.26 in the third quarter of 2007. Our realized gas price was 93% of the average Henry Hub NYMEX gas price in the third quarter, which reflected the wider differentials that we experienced in September as a result of the hurricanes.

We had 12% of our onshore gas production hedged into the third quarter, which reduced our realized price that we reported by $0.21 per Mcf. For the first three quarters of 2008, our average gas price increased 42% to $9.65 per Mcf, as compared to the $6.78 in the first three quarters of 2007. Our realized gas price was 99% of the average Henry Hub NYMEX gas price for the first nine months of the year. For the rest of the year and all of 2009, we have approximately 12% of our gas production hedged at $8.20 per Mcf.

On slide six, we cover our oil and gas sales. Our sales from our continuing onshore operations increased 977% to $164 million in the third quarter due to the higher production level and the strong oil and gas prices. For the first nine months of this year, oil and gas sales increased 96% to $464 million, as compared to $236 million for the same period in 2007.

Our earnings before interest, taxes, depreciation, amortization and exploration expense, and other non-cash expenses, or EBITDAX, from our continuing onshore operations increased 119% in the third quarter to $139 million, as compared to $63 million in last year's third quarter, as shown on slide seven. For the first nine months of this year, our EBITDAX increased 117% to $387 million, as compared to $179 million for the same period in 2007.

Slide eight covers our operating cash flow. Our cash flow just from our continuing onshore operations increased 152% in the third quarter to $133 million, as compared to cash flow of $53 million in 2007’s third quarter. For the first three quarters of the year, our operating cash flow was $359 million, 135% higher than the cash flow we had in the same period of 2007 of $153 million.

On slide nine, we outlined our earnings for the quarter and for the first three quarters of this year. We reported net income of $225 million or $4.91 per share for the third quarter, which is, of course, by far the highest quarterly profit in our corporate history. This compares to $16 million or $0.37 per share for the third quarter of 2007. $55 million or $1.20 per share is attributable to our continuing onshore operations, as compared to $10 million or $0.23 per share in the third quarter of 2007.

Included in our continuing earnings this quarter is an after-tax gain of $4 million or $0.08 per share from the sale of certain South Texas properties. For the nine months – for the first nine months of this year, we reported net income of $348 million or $7.65 per share, as compared to $47 million or $1.05 per share for the same period in 2007. A $154 million or $3.40 per share is attributable to our continuing onshore operations, as compared to $32 million or $0.73 per share in 2007. Included in continuing earnings for the first nine months of this year is an after-tax gain of $17 million or $0.38 per share on the properties that we have sold this year.

We look at our cost structure on slide 10. Our lifting cost in the third quarter improved to $1.44 per Mcfe, as compared to $1.53 that we had in the second quarter of 2008, but we’re up slightly from the $1.40 per Mcfe in last year’s third quarter. Our depreciation, depletion and amortization per Mcfe produced increased to $3.06 per Mcfe in the third quarter of 2008, as compared to $2.73 per Mcfe in 2007’s third quarter.

For slide 11, we outlined our production cost for the first nine months of this year. Our lifting cost averaged $1.47 per Mcfe in the first three quarters of this year, which is the same rate that we had in 2007. Our DD&A per Mcfe produced increased to $2.93 per Mcfe in the first nine months of 2008, as compared to $2.74 per Mcfe in the same period in 2007.

On slide 12, we present our capital structure at the end of the third quarter. On August 28th, we repaid all of our bank debt, which reduced our total debt to $175 million using the proceeds from the sale of interest in Bois d'Arc. On October 29th, our – we affirmed our $590 borrowing base on this credit facility, which means we now have all $590 million available. We ended the quarter with $1.1 billion in equity, reflecting the profits that we made this year. As a result, our percentage of debt to our total booked capitalization decreased to 13% at the end of the quarter, compared to the 50% level where it stood at the end of last year. The company is now very well positioned in this period where credit and the capital markets are very difficult and costly to exist.

On slide 13, we detail our capital expenditures to date this year. We have spent $309 million in the first nine months of this year for our drilling program, as compared to $287 million that we spent in the first three quarters of 2007. We spent $248 on our East Texas/North Louisiana region, $55 million in South Texas, and $6 million were spent on our other regions. $109 million of the dollars spent in the East Texas/North Louisiana was special – additional lease-hold in the Haynesville shale play.

We announced today that we are increasing our capital expenditure budget this year to $425 million, which is detailed on slide 14. Much of the increase is for the acreage acquisitions that we’re making in the Haynesville shale play. We now expect to drill approximately 140 wells or 77.1 net wells to our interest this year. Ten of these wells will be horizontal wells drilled in our East Texas/North Louisiana region for either the Cotton Valley Taylor formation or the Haynesville shale formation.

Our East Texas/North Louisiana operating region at $327 million and accounts for 77% of the 2008 budget, and 116 of the wells to be drilled. We expect to spend $91 million in our South Texas region to drill 18 wells. And we’ve budgeted only $7 million in our other regions to drill 6 wells.

I will now turn it back over to Jay to review the operating results in each of our regions.

Jay Allison

Thank you, Roland, for that exceptional report on the third quarter financial results.

On slide 15, we focus on our East Texas/North Louisiana region. We drilled 96 wells in this region in 11 different fields in the first three quarters of this year. All of these were successful. We have tested these wells at a per well average rate of 2.7 million cubic feet equivalent per day, a substantial improvement from our average in 2007 of 1.4 million cubic feet equivalent per day. The prolific wells at Hico-Knowles and the Cotton Valley Taylor horizontal wells account for the improved per well results.

Slide 16, 35 of the wells drilled in this region have been drilled in the Hico-Knowles field in Lincoln Parish in Northern Louisiana is shown on slide 16. This field offsets the very prolific Terryville field as the Petrohawk has been developing. Thirty two of these wells have been completed and has initial production rates, which have averaged 3.7 million cubic feet equivalents per day.

On slide 17, we have a map of our Waskom field in Harrison County, Texas. We have drilled four successful horizontal wells in the Waskom and Blocker fields in Harrison County, Texas. These wells have a per well average initial production rate of 7.5 million cubic feet equivalents per day. Our average working interest in these wells is 83%.

On slide 18, we have our current view of the emerging Haynesville shale play in North Louisiana and East Texas. Our acreage is highlighted in green. We currently have 85,392 gross acres and 70,004 net acres that we believe are prospective for Haynesville development based on five test wells that we have drilled and data from other wells drilled by other operators that we have reviewed. Given expected well spacing of 80 acres and expected well recovery of four Bcfe per well, our acreage could add 2.6 trillion cubic feet equivalent of reserve potential. We have four horizontal wells in process to begin the commercial development of this play.

I will let Mack, our Chief Operating Officer, go over these wells, and also contrast the Haynesville horizontal wells to the Cotton Valley Taylor horizontal wells that we are now drilling. Mack?

Mack Good

Thanks, Jay.

As shown on slide 19, Comstock targets an interval in the upper Cotton Valley Taylor reservoir through a horizontal completion. This completion normally involves between five to seven fracture stimulation stages that are pumped crossly, horizontal, lateral, that varies between 3,000 and 4,000 feet in length. The fracture stimulations that we pumped are pumped at very high injection pump rates. And they’re all pumped one right after the other without stopping by using an on the fly sleeve shifting technique that has been developed for these kinds of completions.

As a result, all of the stimulation stages are pumped consecutively within a 24-hour period. Currently, we’re drilling our 5th horizontal Cotton Valley well in our 2008 drilling program, and we plan to drill an additional two horizontal Cotton Valley wells before the end of the year. The average drilling and completion cost of these wells approaches $5 million per well. And so far, this year, our average per well recovery has approached 2.9 Bcfe per well with initial rates between 5 million and 10 million a day.

Our 2009 program will include additional Cotton Valley horizontal completions. Our intention is to utilize one of our top drive rigs to drill six Cotton Valley horizontal wells next year. Our program can be adjusted as conditions warrant since numerous additional Cotton Valley horizontal locations are available in our inventory for development.

On slide 20, you’ll see a diagram that will give you a general picture of how we planned to complete our horizontal Haynesville shale wells. This diagram shows that we anticipate completing the Haynesville well varying in thickness between 190 feet to 250 feet, and that we will pump between 9 to 12 fracture stimulation treatments across the wells 4,000-foot long horizontal lateral.

It’s important to note that the Haynesville fracture treatments are substantially different than those traditionally pumped in Cotton Valley horizontal wells. The Haynesville completions take longer, and they’re more expensive. This is because the Haynesville shale is an over pressured reservoir unlike the Cotton Valley. When you pump a fracture treatment and everything else remains the same, the higher the treatment pressure, the greater the cost of the job. They Haynesville shale completion is not only treated at a higher pressure, they’re also more complex, and they take longer to finish. This is because the Haynesville horizontal completion requires a wire line service intervention after each fracture treatment in order to set an isolating plug, and another wire line intervention to perforate the next stage. The Cotton Valley horizontal completion requires no wire line interventions at all.

So since all of this work must be done between stages in the Haynesville horizontal well, only two to three stages can be pumped per day. But an entire Cotton Valley completion involving multiple fracture stages can be done within a single day because no wire line work is required between the stages. But as with all plays, it is the geological work that is the key to determining where to drill and what to target for completion.

Our Haynesville shale, geological, and petro physical work shows that the primary section targeted for completion is found in the lower part of the overall Bossier shale interval. And the depth of this targeted lower lobe interval lies between 10,750 feet and 12,000 feet deep within our acreage position. Our work also suggests that this lower interval varies between 190 feet to 300 feet thick across our acreage.

Interestingly, our G&G work also reveals that the second Haynesville target exist within certain areas of our play acreage. And the secondary target is an upper Haynesville lobe that develops within the same depth interval. But it is not present in all areas of the play. It’s thickness and quality is more a variable than the lower lobe. And we are still working to quantify them. But we do believe that this upper secondary target is prospective.

So far, we have drilled, logged, completed, and tested seven vertical Haynesville wells in different parts of our acreage position in the play. And the cost of drilling to complete these vertical Haynesville test wells currently approaches $2.2 million per well. The cost of drilling and completing a horizontal Haynesville well depends on its location, the depth, length of lateral, and the number and size of the fractured treatments to be pumped. Currently, we estimate these costs will vary between $8 million to $9.5 million per well. The commercial development of the Haynesville shale definitely requires drilling and completing horizontal wells in order to optimally recover the reserves and to be economic.

We’ve recently finished drilling our BSMC LA H#1. It is our first Haynesville horizontal well. And this well is located in our Toledo Bend North area, which is just south of our Logansport field assets in the De Soto, Parish, Louisiana. We have an 88% working interest in this well. And after drilling the well to an estimated 11,750-foot vertical depth, we then drilled a 4,300-foot horizontal lateral targeting the lower Haynesville section that I previously described. We are probably completing this lateral with 10 fracture stimulation stages. And after completion, we’ll simultaneously flow all of these stages to sales.

Comstock is currently drilling its second horizontal Haynesville well. And this well is located within our Logansport field acreage. We anticipate starting completion operations on this well sometime during in early December.

We also plan to move two additional rigs in during the fourth quarter of 2008 to drill Haynesville horizontal wells. Our year 2009 plan is very flexible. But our current intention is to drill an estimated 40 Haynesville horizontal wells by running five rigs throughout the entire year. Additionally, we intend to ramp up our five-rig program late in the third quarter of ’09 by adding an additional two rigs to our Haynesville program.

And with that, I’ll turn it back over to Jay.

Jay Allison

Thank you, Mack.

Slide 21, our South Texas region is displayed on slide 21. In our South Texas region, we drilled 11 successful wells in the first nine months of this year. And we had two dry holes. These wells have been tested at per well average rate of 3.8 million cubic feet equivalent per day. Three of the successful wells were in the Las Hermanitas field in Duval County, five were in Javelina field in Hidalgo County, and two were in the Ball Ranch field, and one was in the Lorenz Ranch field in McMullen County.

On slide 22, we have a map of our Fandango field. We are drilling our first exploratory well in this field, the line decker [ph] #10. This was being drilled to a depth of 16,000 feet. And we’ll target three potential pay sands with a total reserve potential approaching 30 billion cubic feet equivalent.

On slide 23, we covered the sale of our net profits interest properties in East Texas and South Texas as well as two other fields in South Texas that’s sold in the third quarter. The net profits interest properties are non-operated properties that we originally acquired when we purchased DevX Energy in 2001. We sold our interest in the J.C. Martin, AWP and East Seven Sisters field in South Texas, and the Gilmer field in East Texas to two separate buyers in June. The estimated proved reserves attributable to the properties that were sold is 44.3 Bcfe. This works out to a sale price of $2.75 per Mcfe.

Production in 2008 from the net profits interests properties is 8.5 million cubic feet equivalent per day. And these properties contributed $8.5 million to our operating income before income taxes. We realized a gain of $13.9 million or $0.30 per share after income taxes on these sales in the second quarter. We have also sold interest in our East White Point field and Markham fields for $16.4 million. These properties have an estimated proved reserves of 15.3 Bcfe, and we are producing 0.8 million cubic feet equivalents per day in 2008. We realized an after-tax gain of $3.5 million or $0.08 per share on these sales in the third quarter.

Slide 24, on slide 24, we showed the impact on Comstock of the sale of our stake Bois d'Arc Energy to Stone Energy that closed on August the 28th. We received $440 million in cash and 5.3 million shares of the common stock of Stone in exchange for our controlling interest in Bois d'Arc.

The shares of Stone that Comstock received were valued at $211 million, making the total consideration paid to us for our shares of Bois d'Arc approximately $651 million. We recognized a gain of $243 million before income tax and $158 million after income taxes. This equates to a gain of $3.48 per share. The cash portion of the sale will create a current tax liability of $146 million for Comstock that we will pay in the fourth quarter. We used the after-tax cash proceeds of $294 million to reduce debt.

2008 outlook, slide 25, in summary, Comstock is very well positioned to continue to grow and add value for our stockholders, especially in the challenging environment that we are in today. Our expanded onshore drilling program will be funded exclusively from operating cash flow, and will position us for continued growth in 2009. We expect to spend $425 million on our drilling program in 2008, with the increased spending in our East Texas/North Louisiana region primarily used for expanding our Haynesville lease holdings.

We are targeting to have 30% to 33% production growth in 2008. Our position in the emerging Haynesville shale play exposes us to 2.6 trillion cubic feet equivalent of reserve potential. The divestitures of our stake in Bois d'Arc Energy and the non-core properties that we completed provided us an extremely strong balance sheet that will allow us to aggressively support the continued growth of our onshore operations, which is increasingly important given the tight credit environment that we’re in today.

We are well positioned for future growth in 2009 with a large inventory of drilling locations in the Cotton Valley and the Haynesville shale in East Texas and North Louisiana, and in the Vicksburg and Wilcox trend in South Texas.

Becky, at this time, I’ll turn the meeting back over to you, and open it up for questions.

Question-and-Answer Session

Operator

(Operator instructions) And your first question comes from the line of Wayne Andrews of Raymond James. You may proceed.

Wayne Andrews – Raymond James

Good morning, gentlemen, and congratulations on an outstanding quarter. I have just some couple of questions, just detailing a little bit on Haynesville and showed us your capital spending plans. I know it’s under our budget process for next year. You, fortunately, have the ability to spend as you see fit. As you allocate capital, I was just kind of curious, Jay, are you looking more – it’s just a mix change in your production and development wells that you drill versus exploration and holding acreage? And I have a follow up question after that.

Roland Burns

Wayne, what we do – we look at, again, like you feel like in 2008, when we started out the year saying we’d have about $278 million in our CapEx. But as we mentioned, we thought our pre-cash flow from operations would be, at the end of the first quarter, of course, commodity prices were higher. We increased that CapEx budget to $327 million. And then, at the end of the second quarter, as you know, commodity prices continued to be higher, and we increased that to $415 million. Today it’s $425 million. And all of that is funded out of free cash flow.

What we’re doing now is we’re kind of tending to our knitting. Between now and year-end, our goal is to complete the line decker well. We want to TD it and complete it. If it works, we’ve got several years worth of drilling there. So we’ll allocate dollars in ’09 accordingly.

And then I think the same way with the Haynesville wells. We’ve got four that are spotted. We hope to have a couple completed by year-end, hopefully, connect it to sales. That’s our goal. I don’t know if we’ll achieve that goal, but we’re trying to do that. I think we’re going to allocate the dollars to drill these 40 wells in the Haynesville. And a lot of that depends upon the outcome.

As you know, you’ve noticed for 13, 14 years, or however many years, we operate most of the wells that we proposed to drill. So we will – we kind of shuffle those dollars around. And when I think – if cash continues to be teeming, then I think we’re going to be stronger as the next months or years go on because of our balance sheet. And I think that we will see some opportunities to maybe acquire some acreage in the Haynesville that’s maybe a little more enticing other than it has been in the past.

But we’re going to continue to run the company, not to grow a giant company, but to create value to the shareholders on a per share basis. So we’re going to be moving those dollars around.

Wayne Andrews – Raymond James

Maybe just a follow up there, you spent a significant portion in your budget this year on acreage. Could you envision that being a similar proportion of spending next year? And then, I know a lot of your acreage has been held by production because of your early into East Texas and North Louisiana. So I would assume you don’t have a large amount of spending that’s required to hold acreage. But maybe you could comment on that, just your – what your thoughts are as far accumulating additional acreage here? And even, just if you can, a quick update on maybe what’s the prices that are paying? And I’d expect that you’ve seem some moderation there.

Jay Allison

Yes. I think if you look at our divestiture of four or five properties for the $141 million in ’08, we took those dollars and we re-employed those in the Haynesville area, as you know. So we didn’t – we didn’t borrow money to increase our acreage. And we didn’t issue shares. We just got out of some areas that were not core to us, and we re-employed those dollars in our core area.

What I think you all see is that this year and ’09, is you’ll see us spend a lot more money drilling, and completing, and producing wells. We went from maybe 30,000 acres or so, 35,000 acres in the Haynesville to a little over 70,000 acres. I think we acquired those acres the right way. But I think now is the time to start drilling and increase the value.

I don’t think we’ve created the value by acquiring acreage. I think we create value, proving that the acreage is good and producing. So I think you’ll see our CapEx budget is skewed a lot more toward drilling, and completing, and producing the acreage that we acquired in 2008.

As far as the cost of acreage, my – I’ll turn it over to Mack. I’ve got an answer, but I’ll let Mack – I’ll let Mack tell you what the acreage is currently doing for – from what we’re seeing in the Haynesville.

Mack Good

Wayne, as you know, the cost of the acreage has come down just simply because the land grab episode is basically over, at least for the moment. Various companies have set back at the end of the year from pursuing – aggressively pursuing additional acreage. So we’re seeing substantial reductions in the cost of this acreage now.

Having said that, a lot of the acreage that we’re seeing is on the fringe of the play, it’s on the edge. We do have our sights set on a few additional filling acres where we think it’s appropriate. But the cost definitely has come down substantially from the hay day of the $25,000 to $30,000 per acre. And we’re seeing tremendous fall offs from those levels, that’s for sure.

Wayne Andrews – Raymond James

And then, maybe just a little comment on how much of your acreage is already HBP because of your early entrance into the area.

Mack Good

We have about 35,000 acres HBP, and 35,000 acres – net acres, of course, is on the three-year clock. We’ve got a really jumpstart on protecting that acreage this year. We plan to drill six Haynesville penetrations, and get four horizontals built before the end of the year. That’s our goal to go into sales. All of the wells that we’re drilling are in different areas. So we’re protecting acreage in each of those areas.

Jay Allison

Wayne, and as an operator in each of our areas, we’re trying to understand each of our core areas. I mean we’re not bringing in a partner to develop our acreage. We’re developing it ourselves. I don’t think we acquired too much acreage so that we didn’t understand it. I think we acquired probably about the right amount. So we could develop it on our timeframe. And we wouldn’t have a lot of wells that we would have to drill to hold acreage that might be expiring.

Wayne Andrews – Raymond James

Great. Excellent results, and looks like a bright future. Thank you for your comments.

Jay Allison

Thank you, Wayne.

Operator

And your next question comes from the line of Ron Mills of Johnson Rice. You may proceed.

Ron Mills – Johnson Rice

Good morning. Wayne’s a tough act to follow. I’ll start off a little bit different with you, just with respect to the North Louisiana drilling, particularly on the vertical program. You talked about switching to kind of higher return areas with Logansport and Hico-Knowles. You’ve had a dramatic difference in terms of our vertical Cotton Valley well activity in the past. As you look at Logansport and Hico-Knowles, what does that inventory look like going forward? And the economics in those areas, can you walk through again your costs and reserves for those areas?

Mack Good

Sure, Ron. This is Mack. We have an excellent inventory remaining in Logansport. And we definitely have included drilling a number of wells in our next year budget planning. The cost of drilling to the Cotton Valley and the completion is around $2.5 million per well. That’s for vertical, of course.

We’re seeing reserve recoveries anywhere from 0.75 to 1.5 Bcfe, average is probably a little over one Bcfe. The economics are excellent. We’re getting – there are different parts of Logansport that give us different performance profiles. But we’re quite pleased with this year’s program, and it set up a significant number of additional drilling opportunities going forward.

Ron Mills – Johnson Rice

And as you look through the horizontal program, it sounds like you’re planning on drilling six wells next year, targeting the Cotton Valley. What’s the depth of your horizontal inventory? I know that that’s less of a blanket opportunity, if you will, and more field specific, i.e. Blocker and Waskom. I’m just curious as to how much opportunity you have on the horizontal side?

Mack Good

We think we’ve got a substantial inventory remaining going forward. We tailored back a little bit on our Cotton Valley horizontal program this year to make room for some Haynesville tests. But we’ve got substantial opportunities remaining in Waskom. We’ve also drilled one in Woodlawn that we’re quite pleased with. We have remaining opportunities there. I can’t give you an exact remaining inventory on the Cotton Valley horizontal. But certainly, it would be a multiple year program with one to two rigs. That’s for sure.

Ron Mills – Johnson Rice

And on the Haynesville, you talked about, once again, the kind of upper and lower lobes. Just for clarification, the 193 feet to 300 feet of Haynesville (inaudible) that was discussed earlier, is the 193 feet to 300 feet primarily in the lower lode, and in the areas that you have, the upper Haynesville that’s incremental or is that included in that figure?

Mack Good

Yes. The 190 feet to 300 feet is just lower lobe alone, Ron. And the upper lobe is much more variable. But on average, about 150 feet thick for the upper lobe is what we’re seeing.

Ron Mills – Johnson Rice

And it sounds like that varies over your acreage – of your acreage. Any guesses of via your seven, excuse me, vertical test, how much of it is subject to that second lobe versus just lower? I’m asking because the question is how do you then effectively develop the upper lobe as well (inaudible) the development?

Mack Good

Absolutely. That’s a great question. Currently, it’s more cost effective to drill a second well for that upper lobe. All of the petro physical data suggests it would be economic to do so. But right now, for obvious reasons, we’re targeting the lower lobe. It’s thicker. It’s more predictable. And until we get more data on the upper lobe, as I mentioned earlier, we’re still working on identifying and quantifying that upper lobe, where it is and the quality of it, et cetera. But there’s no doubt that we will be drilling a well targeting the upper lobe in the not too distant future. Like I said, all of the data that we have thus far indicates that it’s highly prospective and it would be economic to drill a well.

Now, having said all of that, we’re investigating the different mechanical options that might be available for multiple lateral off of a single well bore. And to date, we haven’t found a solution that we think is cost effective.

Ron Mills – Johnson Rice

Okay. And then, Roland, in terms of your outlook for the 2009 budget, to follow on Wayne’s question, would you expect, overall, to spend a similar amount of capital in 2009 just with much greater (inaudible) on the drilling side rather than the leasing side? I’m just trying to get a sense as to what it’s going to look like? I would assume that you plan on spending a little bit more than your cash flows given the current commodity environment to maintain your activity levels, particularly in the Haynesville?

Roland Burns

Yes. That’s correct, Ron. I think we’ll be continuing to look at what we’re going to spend in 2009, and kind of base it on what – how the outlook for natural gas prices turn out. And we’ll probably make our – set our final budget in early December, and submit that to the Board for approval. I would think that the lower end of the range in our budget could be – would be an amount similar to what we’ve spent this year.

And yes, that we have numerous – we have more opportunities for drilling 2009, probably more than we’d ever had in the company’s history. But I think we want to be prudent about our spending given the tight credit market and the tight capital market. And while we might overspend our cash flow by a small amount, we don’t plan to overspend it by multiples. So I think even if the opportunities are there, we want to be very judicious about how we use the balance sheet and maintain that strength because I think that’s an important strength as long as we’re in this pretty vulnerable type of economy.

Ron Mills – Johnson Rice

Okay. And Jay, South Texas, the Fandango well going down, to touch base, what kind of opportunities that you see in that area in terms of future development?

Jay Allison

Well, just pertaining to the line decker well, remember the wells are about a $9 million well to drill, complete, and produce. Now that’s our initial estimate. The wells should be drilled between 16,000 feet, say 16,200 feet in depth. And there are three different Wilcox packages that we hope to penetrate. And again, if you remember, I mean the field was developed in the late 70s. Some of those wells came 40 Bcfe. And then when they came back in the late 80s, they were about 12 Bcfe.

So we’re not trying to discover something that hadn’t been discovered in the past. I think we’ve taken a field that’s shale renowned. They now spend a lot of time developing it. We use the same type of technology that we did in offshore, the shallow waters, which is three-deep. And we’ve used that in South Texas. We’ve been very successful since ’05 in using it. We’ve applied it to the Fandango. And we expect that it’ll work to some degree in our – our buggy out there and we throw it out. I mean it could be a $9 million dry hole. Or we think, the other side, somewhere 30 Bcfe or greater. It is a top prospect, Ron, that we’ve been good at in the past. And I think it complements the horizontal program, which is the Cotton Valley Taylor and Haynesville in East Texas/North Louisiana.

So Mack, you want to make any other comments from there? We can’t seem to give a micro update on it yet.

Mack Good

We’re very happy in what we’re seeing so far in the line decker, Ron. We got a zone behind pipe, and suffice it to say that we can stop right there and be happy with the well. We have two other zones that we want to go for. And we’re about 2,000 feet or so away from CD. Give us another few weeks and we should have some good news.

Ron Mills – Johnson Rice

And will that set up multiple drilling locations?

Mack Good

Absolutely.

Ron Mills – Johnson Rice

All right, great. Thank you.

Mack Good

You bet, Ron.

Jay Allison

We want to get another schwim back for Christmas. It’s that tough will.

Operator

And your next question comes from the line of Kim Pacanovsky of Collins Stewart Llc. You may proceed.

Kim Pacanovsky – Collins Stewart Llc

Good morning, guys.

Jay Allison

Hi, Kim.

Kim Pacanovsky – Collins Stewart Llc

I was wondering if you’re going to talk about when all the shareholders get their schwim bay.

Jay Allison

That’s right. There are 45 million shares, and we want everybody to have one. And we chose red, but you might pink.

Kim Pacanovsky – Collins Stewart Llc

First of all, I want to say – I want to say congratulations not just on the operating results, but on the balance sheet. And I truly do think you’re in a unique position among your peers with your balance sheet. So congratulations on that.

Jay Allison

Thank you.

Kim Pacanovsky – Collins Stewart Llc

As far as the bread and butter business is concerned, what are your rig commitments looking like? And what is your ability to cut CapEx should gas pricing get really ugly in ’09?

Jay Allison

Well that’s a good question. And I appreciate you asking it because that is another advantage, I think, that Comstock has going forward and that we have a flexible rig inventory.

We have four rigs currently committed on long-term contract. We have three other rigs – pardon, we have four other rigs that are going to be available for early release. So we can mix and match. We can extend contracts subject to more favorable terms. We can release rigs. We can move rigs that are available for horizontal Haynesville drilling into our Cotton Valley horizontal program. And even if we wish, we could also move them into a vertical drilling program with less expensive wells.

So we are at a very enviable position, I think. Some of the other companies that we compete with have obligated to significantly greater rig inventories at contract cost that were locked in several months ago at higher rates. We have four of those that we’re currently committed to for long term. But we have, I mentioned, numerous other that are far more flexible that we can release early.

Kim Pacanovsky – Collins Stewart Llc

Okay, good deal. And can we just go over the rig situation for the Haynesville again right now? You have operated rigs, correct, and one not on, is that correct?

Mack Good

Currently we have, for the Haynesville, we’ve got three rigs that are operating, drilling Haynesville. And we have one – all of these rigs that I’m mentioning, Kim, are equipped to drill horizontal wells, one rig that’s drilling in the Cotton Valley that could come over to the Haynesville if we desire.

The other rigs that are drilling vertical wells, two of those three are drilling what we call vertical set up wells for the Haynesville that’s to help us ramp up our initial testing of the Haynesville. These rigs will drill the vertical section of the holes. And then, later we’ll have our horizontal rigs coming in and drill the lateral.

Kim Pacanovsky – Collins Stewart Llc

Okay, so that’s why the in your press release that, Bogue, I don’t if I am pronouncing it correctly, the Bogue well?

Mack Good

Yes.

Kim Pacanovsky – Collins Stewart Llc

Okay, that why well is waiting about 30 days or so before the horizontal kick out starts?

Mack Good

That’s exactly right.

Kim Pacanovsky – Collins Stewart Llc

Okay, okay. So now, the five rigs that you’re going to have on all year next year, does that include – let’s see. Does the three that you have now and then there two more coming on before the end of the year?

Jay Allison

Yes. I’ll tell you, it’s gets confusing when you start talking about our rig schedule. But we have a rig coming in next month that will put us at four rigs drilling Haynesville horizontal wells exiting the year. And then very early, probably January, we have another rig arriving that will give us our fifth rig that will be running in the Haynesville all year. And then, we have two additional rigs scheduled for delivery in the late third quarter of next year.

Kim Pacanovsky – Collins Stewart Llc

Okay. And are those rigs on – are the Haynesville rigs on long term contract?

Mack Good

Four of them.

Kim Pacanovsky – Collins Stewart Llc

Four of them. Okay. Right, okay. All right. And I know you haven’t officially issued the 2009 budget or guidance, but when you look at your internal models, what sort of per well rate assumptions are you guys going to be using on your Haynesville wells?

Mack Good

On the IP’s you mean?

Kim Pacanovsky – Collins Stewart Llc

Well, IP’s, or first three months production or – ?

Mack Good

The first 30 days, we’re assuming around $5 million a day, Kim. Now, that assumption is based on looking at some of the available long term production data. And believe me, there’s not a whole lot of Haynesville long term production data. Long term meaning six months, three to six months, a little longer. There are numerous wells, and I am sure you are familiar with some of them, that in the last 60 days have come on at $10 plus million a day first 30 days average.

There are a couple of other wells out there they have 60-day averages that are around

$8 million a day. An argument could be made based on where you are in the play, what’s your targeted interval, what it looks like compared to those excellent wells as to what the rate will be. But we’re fairly conservative, as you know, on the EURs and the IP rates on the Haynesville compared to some of the other press releases that are out there.

Kim Pacanovsky – Collins Stewart Llc

Okay. And when you’re – I know that Chesapeake runs seismic on everything that they do, do you guys see any need for running any seismic over your acreage, and I don’t know if seismic is potentially helpful when you’re looking at this upper lobe?

Jay Allison

Well, we’ve looked at that, and we’ve run vertical seismic or micro seismic during the fracturing of a couple of our vertical tests that has given us some valuable information on fracture orientation, et cetera. We’re not quite sure as to whether or not 3D seismic would be all that helpful in the Haynesville play. But we’re still studying that issue.

Kim Pacanovsky – Collins Stewart Llc

Okay. And finally, well almost finally, I have two more questions. When you have a rate on that Toledo North well, are you going to issue a separate press release for that or do we have to wait a really long time?

Roland Burns

If it’s a good rate.

Kim Pacanovsky – Collins Stewart Llc

Okay. So if we don’t hear anything, we know.

Roland Burns

Most likely, given the fact that we weren’t able to get it tested for this conference call. And then, the year end conference call is even further away than the quarterly ones. I would think we would come up with an update, probably after – typically after maybe Thanksgiving. And somewhere around December we will come out with an update, obviously, what the budget we’re going to go into up to 2009 with. So it sounds like it will be a drilling update that we’ll come out before the end of the year along with our press release on the budget.

Jay Allison

And that would probably include South Texas also.

Roland Burns

Right. Because we have a big South Texas well.

Kim Pacanovsky – Collins Stewart Llc

Right, right. Okay. Is that well cleaning up now? Are all the frac stages done? What’s the actual status right now?

Jay Allison

On the horizontal Haynesville well?

Kim Pacanovsky – Collins Stewart Llc

Yes.

Jay Allison

Now, we’re still completing it.

Kim Pacanovsky – Collins Stewart Llc

Oh you are. Okay, all right. And for Hico-Knowles, and this is really is my last question, your average for the nine months was $3.7 million a day per well average IP rate, right? And at the of the second quarter, it was $4 million a day. Did you drill the best first, and we’re just looking at the rate coming down because the – ?

Jay Allison

Yes, that’s correct. And that’s always what we are try to do is drill the best first, Kim.

Kim Pacanovsky – Collins Stewart Llc

Okay.

Jay Allison

And that’s what Petrohawk has done.

Kim Pacanovsky – Collins Stewart Llc

Okay. But there is nothing weird going on there?

Jay Allison

No, no, not at all. And the differences is marginal when it comes to the economics.

Kim Pacanovsky – Collins Stewart Llc

Okay, great. Al right, guys. Thanks a lot. That’s all I have.

Jay Allison

Yes. Thank you.

Operator

And your next question comes from the line of David Snow of Energy Equities. You may proceed.

David Snow – Energy Equities

Yes. Hi, I’m just trying to see the incremental changes in your Haynesville. The CapEx and the cost per well went from $6 million to $8 million to $9.5 million. What was the factor in that?

Mack Good

Multiple factors, one location cost, building the location, that increased. As you probably know, pipe has increased by 60% to 80% over this time last year. We are starting to see some softening in that. But rig rates also went up. And the cost of additional or the other services, pumping services, wire line services, et cetera, went up significantly as well. And the initial cost, and most operators did this, were modeled after the Barnett and after finding that the Haynesville, as I indicated earlier, is an abnormally pressured reservoir requiring higher pressures to pump the jobs away. The number of stages increased from four to six to ten stages on the lateral. All of these things added up to increasing the cost per well.

David Snow – Energy Equities

Okay. What would be an IRR on a Haynesville well now if you say had a 750 flat price?

Mack Good

Well, it’s going to be plus 20% at the $9 million level. And it depends upon how you front end load your production profile. Different side curves have different front end loading, different assumptions built into that. So that will obviously affect your rate of return. But we use a 20% internal rate of return hurdle that we measure all of our projects by. Most operators have similar hurdles.

David Snow – Energy Equities

I was just trying to get to an idea what the difference in rate of return would be, internal rate of return on the Haynesville versus Cotton Valley Taylor horizontal at a given price that you could give us?

Mack Good

Well again, they are different profiles, et cetera. But to try to answer your question, we’re looking at the Haynesville, obviously, generating a significant rate of return because of the – and it’s early in the game. And it’s based on sparse data I mentioned earlier. But the production from the Haynesville is very much front end loaded. You get 70% of your production to 80% of your production in the first two years. You’re talking higher EURs. You are also spending more money. But those EURs – everything else is being the same.

The Haynesville that you are at four Bcf, conservatively, is front end loaded in the first 18 months is going to give you theoretically a higher ROR than an average Cotton Valley well. But the caveat here is that we know a lot more about the horizontal Cotton Valley performance profile than we do about the horizontal Haynesville profile. That’s why it’s called emerging play, to be frank. And we are very confident, very optimistic about the results going forward. But I’m afraid I can’t be more specific in answering your question because I just don’t have the information yet.

David Snow – Energy Equities

And the other thing that you have increased is, the thickness was 198 to 250. And I think that in your last conference call, that was 120 in the lower bench. And now you are at a very attractive increased 190 to 300, and it’s all lower bench. So have you added to you database or what happened to cause that incremental change?

Mack Good

That’s a good question, too. And your statement is correct. We have added significantly to the database and how we have evaluated the logs and the core data that we have available has changed with additional information. So rolling all of those comments up, you are exactly right. We have more data at the base or thickness estimates on.

David Snow – Energy Equities

Okay. And then I’m just trying to get an idea, you’ve got around 200,000 net acres in the Cotton Valley overall, how much of that would be applicable to both to the lower Taylor horizontal?

Mack Good

Well I can’t give you an acreage count on that.

David Snow – Energy Equities

Well just roughly a percentage.

Mack Good

I would say 20%.

David Snow – Energy Equities

Oh okay.

Jay Allison

What we’re drilling, David, we think we have several years of drilling. We have not quantified it. So I don’t think Mack really can quantify it because we have never done that. We have couple of years drilling. And couple of years you can ask again, and we’ll tell you.

David Snow – Energy Equities

Oh okay. And is the rate of return, I would think, significantly better for Taylor horizontal than for the Cotton Valley vertical, what the incremental difference in IRR would you have on that?

Mack Good

I can’t give you that number either, but I can tell you that the rate of return is substantially greater. It depends on where you drill the vertical. What kind of vertical you are talking about, what the location is.

David Snow – Energy Equities

Do you have any idea what the plan on Petrohawk will be for the Terryville next year?

Mack Good

I think we are going to fall back quite a bit. They’ve drilled a lot of wells this year. And I think they’re going to transition over to a couple of the other fields, and also allocation dollars into the Haynesville.

David Snow – Energy Equities

Okay. And then last, what do you think your year-end cash will be? I mean, you have got a lot of moving targets. You have to pay the tax on your gain and so forth. You will be about even at the end of the year?

Roland Burns

Yes, David. This is Roland. We will be paying $144 million kind of tax liability on December 15th. So a lot of the cash on our balance sheet at the end of the quarter, the $118 million, it has been earmarked for that. We typically would – will have $5 million to $10 million of just cash on hand for working capital. We anticipate having to draw anywhere from really $30 million to $60 million, that kind of range ,under the credit facility to fully fund the CapEx and the tax payments in the fourth quarter. It really depends on kind of gas prices continue to be and other factors.

David Snow – Energy Equities

Okay. Thank you very much.

Jay Allison

Thank you, David. One other thing, Petrohawk did and has done a good job in the development of the Terryville area.

David Snow – Energy Equities

Yes.

Operator

(Operator instructions) And your next question comes from the line Dan McSpirit of BMO Capital Markets. You may proceed.

Dan McSpirit – BMO Capital Markets

Thank you, gentlemen, good morning.

Jay Allison

Hi, Dan.

Dan McSpirit – BMO Capital Markets

Your acreage or the estimates that you think is perspective for the Haynesville is now what, 70,000 net acres. How much upside is that – is there to that number assuming no acquisitions – and as you continue to march through your acreage position and testing the rock?

Mack Good

Is the question how many additional acres do we think we could acquire?

Dan McSpirit – BMO Capital Markets

Not acquire. Assuming new acquisitions, how much upside is there to that estimate today of 70,000 net acres assuming no acquisitions and just simply based on drilling results and continued testing of the acreage of your planned position, is there any?

Jay Allison

Well, we’ve got several hundred thousand net acres in that core area. And what we do on adding quote Haynesville prospective acreage is we see what peer companies do to the North, South, East, and West, being they have in Canada and the others. And then based upon their success or lack off, and we can adjust our acreage. But we think we have a solid 70,004 acres right now. And unless we actively acquire additional acreage, which we do. I mean we do that daily. We have offers out daily, but I think it’s a pretty solid number, Dan.

Dan McSpirit – BMO Capital Markets

Okay, okay. And then one last question on the balance sheet, maybe more theoretical than anything, you have recognized that your financial strength equates or implies great financial flexibility. But do you think you are too conservatively financed or capitalized at this time? And if you were to conduct an acquisition, are the capital markets, either equity or debt capital markets, opened to Comstock permanently finance such an acquisition?

Jay Allison

Well, I think right now, if you look at the strength and weaknesses of companies, I think Comstock generates, for the size of company we have, a very meaningful cash flow on a per share basis. And I think we have very limited exposure to the credit market constraints because we just had our borrowing base re-determined.

And I think we have very limited execution risk because we don’t rely upon partners to execute our business plan. And we don’t rely upon the equity market to pay down an acquisition or land that we have just acquired. And I do think, to kind of answer your question, I think that in – a corporate life span of an E&P company, I think you have to have some kind of a rare event to boost who you are and separate you from kind of peer companies. And I think that the creation and the sale Bois d’Arc did that for Comstock.

It took our bank debt to zero. It reaffirmed our borrowing base. In fact, I think we could have asked for an increase in that if we want to pay a few more dollars. And we did want to pay a few more dollars. I think that the way we acquire on a non-diluted basis our acreage in the Haynesville and other areas, I think lends itself in 2009 to create wealth on a per share basis.

And you are asking about additional acreage. I think that some of these companies don’t have an upper and lower lobe. And we’ve mentioned that quarter or two ago, and it was kind of weird thought, but we were not a new comer to the Haynesville. We have been there since probably the middle of last year. And we just reported what we saw. We didn’t repeat what we heard. And I think that’s a big difference in who we are.

So you add all of those little elements together, and you always say timing is everything, and our divestitures of those properties and our divestiture Bois d’Arc happening when it happened. I think that if there is a company out there that has a chance to creating real wealth even without acquiring acreage, it’s because – we have free sources of dollars. We have free cash flow from operations spend to grow. That’s not diluted.

We can use part of our borrowing base that’s why it’s there. I think a company that has 35% debt-to-cap is not over levered. Particularly, if you have high cash margins like we have, so we can use our borrowing base. And then I think a year from now, we have the right to sell our Stone shares. Now that’s not a plan that we have, but if the Haynesville or the Wilcox, or the Vicksburg, or the Cotton Valley Taylor is blowing and going for us corporately, then we think we can have more value by divesting ourselves with Stone and redeploying those dollars into our own account.

We can do that and that’s not dilutive either. And you are talking about hundreds, and hundreds, and hundreds, and hundreds, and hundreds of millions of dollars, and the company’s asset base is only $1.8 billion. I mean that’s a pretty strong company. And that’s what we will continue to do.

Mack Good

Dan, and your question about the capital market and the credit markets being available at this point, at this time. I would say that they are probably available to the strong companies. And I don’t think Comstock is in that category. I mean I think the cost to the capital in their credit, or equity, or any type of capital you want to get is substantially increased now even from the strong companies. I do think we are in a market where the weak companies don’t – won’t have access to those markets, or be very, very expensive almost to the point where it’s going to be worthwhile to do.

Jay Allison

Well even going into that, on October the 16th, Dan, and this was – it’s one of those positive pleasant surprises. When S&P notifies that the Comstock have been placed in the S&P mid cap 400 U.S. industries, we had a bunch of investment bankers call and say, “These index funds left about hundreds and hundreds and hundreds of millions of dollars of Comstock. Do you want to raise equity?” So as recently as two or three weeks ago, we were invited to do that. And again, I think that goes back to your question of would we will be able to. I don’t know. But I think if any company would have the numbers to do that, we certainly would have those.

Dan McSpirit – BMO Capital Markets

Agreed, thank you.

Jay Allison

Thank you.

Operator

And I am showing that you have no further questions at this time. Gentlemen, I will turn the call back over to you for closing remarks.

Jay Allison

Again, we’ve had an unbelievable quarter. We’re very thankful for that quarter. And I guess, in closing, it’s kind of a simple comment, but if – if we’re all out there kind of participating in a weight lifting contest, it’s kind of a nice to have some meat on your bones. And right now, Comstock has a lot of muscle on its bones. I think its technical group has never been more effective and we’ve never had greater depth in all of our departments. It’s the employees that create the wealth and we truly work for you. We do try to put in a good day's work and sometimes the outcome is good, sometimes it is bad. It’s our intention to always have it good. So anyhow, thank you for your time. I know it’s valuable, we were to go vote. Thank you.

Operator

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

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Source: Comstock Resources, Inc. Q3 2008 Earnings Call Transcript
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