Comstock Resources Inc (CRK) 2005 Q3 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the third quarter financial results conference call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Please note that this conference is being recorded. I would now like to turn the call over to Mr. Jay Allison. Mr. Allison, you may begin, sir.

Thank you, Sandra. Welcome to Comstock Resources third quarter 2005 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 third quarter 2005 results, to change the page in the presentation, click on the arrow on the page. 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. With this call, I will review our 2005 third quarter financial and operating results, as well as the results of our 2005 drilling program.

Our discussions today will include forward-looking statements within the meaning of the securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurances that such expectations will prove to be correct. Page 2 on the webcast, 2005 third quarter highlights. What I would like to do is go over our highlights, then go over the regions, and then I would like to make some comments and then, at the very end, and I would like to tell you this early on, is I want to turn it over to Mack Good, our COO, to give you a preview of what our thoughts are on our 2006 drilling program.

Strong oil and gas prices contributed to strong financial results in the third quarter of this year. Our revenues reached $72 million and we generated EBITDAX of $59 million, and operating cash flow of $53 million. We also generated a profit of $26 million, or $0.60 per share, excluding the unrealized mark-to-market loss on our hedge position.

Our net income was hampered by the write-off of additional costs to the dry hole at Big Sandy, and the write-off of a one-well field in south Texas, which reduced our net income by $4 million, or $0.09 per share. Apart from the Big Sandy, our drilling program has been successful with a 97% success rate, having drilled 59 wells with only two dry holes. We closed three major transactions last quarter, that have transformed the Company and positioned it for future growth.

The $191.6 million inside acquisition added 18 million cubic feet equivalent per day to our production, and added 424 drill sites to our onshore drilling inventory. To strengthen our balance sheet, we sold 4.5 million shares of stock, at $27.50 per share in a public offering. On May 11, Bois d'Arc closed its initial public offering at $13 a share, and is now trading on the New York Stock Exchange.

Page 3, average daily production. Production in the third quarter of 2005 averaged 118 million cubic feet equivalent per day, which is increased 4% from our daily production level in 2004's third quarter, and is decreased 9% from our second quarter production rate of 130 million cubic feet equivalent per day. Our share of Bois d'Arc Energy's production averaged 25 million cubic feet equivalent per day in the third quarter. Bois d'Arc's production was down because of the hurricane activity in the third quarter which caused Bois d'Arc to defer 30% of its production in the quarter.

Our onshore production averaged 93 million cubic feet equivalent per day, which was up 25% over our onshore production in last year's third quarter, and was up 2% from our second quarter production. Onshore production was also hampered by the hurricanes, and would have been 4 million cubic feet equivalent per day higher without the deferred production that was shut in in the third quarter.

Page 4, average daily production. Looking at just our onshore production, we averaged 93 million cubic feet equivalent per day in the third quarter. Our east Texas/north Louisiana region averaged 44 million cubic feet equivalent per day, our southeast Texas region averaged 17 million cubic feet equivalent per day, and our south Texas and other regions averaged 32 million cubic feet equivalent per day, during the third quarter of 2005. Without the hurricanes, we would have averaged 97 million cubic feet equivalent per day in the third quarter.

In the fourth quarter, we are expecting production to increase to approximately 100 to 108 million cubic feet equivalent per day.

Page 5, average oil price. Oil prices are up substantially this year. Our average oil price increased 24% in the third quarter of 2005, to $52.71 per barrel as compared to $42.46 per barrel in the third quarter of 2004. In the first nine months of 2005, our average oil price increased 28%, to $48.68 from $38.12 in the same period in 2004.

Page 6, average gas price. Natural gas prices have started to catch up with oil prices. Our average gas price increased 42% in the third quarter of 2005, to $8.28 per MCF, as compared to $5.83 per MCF in the third quarter of 2004. In the first nine months of 2005, our average gas price increased 22% to $7.01 from $5.75 in the same period in 2004.

Page 7, oil and gas sales. To best compare oil and gas sales, we have broken out onshore and offshore. We have also included the sales that we did not pick up from Bois d'Arc as a result of changing to the equity method. For the third quarter of 2005, our oil and gas sales increased to $93 million, which represented a 45% increase from 2004's third quarter oil and gas sales at $64 million. For the first nine months of 2005, our sales increased 28%, to $244 million as compared to the same period in 2004 sales of $190 million.

Page 8, EBITDAX. Our earnings before interest, taxes, depreciation, amortization, and exploration expense, and other non-cash expenses, increased 23% in the third quarter of 2005, to $59 million, as compared to $48 million in the third quarter of 2004. For the first nine months of 2005, our EBITDAX increased 14%, to 168 million as compared to EBITDAX for the same period in 2004 of $147 million. Using the equity method of accounting for Bois d'Arc, we no longer pick up any of Bois d'Arc's EBITDAX starting May 10.

Page 9, cash flow. Our cash flow from operations increased 16% in the third quarter of 2005, to $53 million, as compared to cash flow of $46 million in 2004's third quarter. For the first nine months of 2005, our cash flow increased 14% to $147 million, as compared to $129 million for the first nine months of 2004. Using the equity method, we did not include $25 million in operating cash flow related to our share of Bois d'Arc's operations after May 10.

Page 10, earnings. Excluding the mark-to-market losses from our derivatives, we reported net income of $26 million, or $0.60 per share, as compared to net income of $13 million in the third quarter of 2004, or $0.37 per share. The third quarter included an additional 2.4 million in costs related to the Big Sandy dry hole, and an impairment of $3.4 million on a south Texas field that watered out early. These two items lowered net income per share in the quarter by $0.09 per share. Excluding the derivative losses and the loss from the conversion of Bois d'Arc to a taxable corporation, we had net income of $55 million, or $1.35 per share in the first nine months of this year, as compared to net income of $45 million, or $1.24 per share, for the same period in 2004, excluding the loss on early retirement of debt.

Page 11: Third quarter costs for MCFE. With rising oil and gas prices, our units costs have been increasing also. Our lifting cost for MCFE produced increased $0.06 in the third quarter 2005 to $1.26, as compared to $1.20 in the third quarter of 2004. Our G&A for MCFE, excluding stock-based compensation, increased $0.03 in the third quarter of 2005 to $0.24, as compared to $0.21 for MCFE in 2004's third quarter. Our depreciation, depletion, and amortization for MCFE produced increased $0.15 from the third quarter of 2005 to $1.62 for MCFE, as compared to $1.47 per MCFE in 2004's third quarter.

Page 12, nine months costs per MCFE. Our lifting cost per MCFE produced in the first nine month of this year increased $0.10 to $1.26, as compared to $1.16 for the first nine months of 2004. Our G&A per MCFE, excluding stock-based compensation, increased $0.05 in the first nine months of 2005, to $0.23, as compared to $0.18 per MCFE in 2004's first nine months. Our depreciation, depletion, and amortization per MCFE produced increased $0.19 in the first nine months of 2005, to $1.61 per MCFE, as compared to $1.42 per MCFE in the first nine months of 2004.

Page 13, drilling expenditures. We spent $127 million on drilling our program in the first nine months of this year, as compared to $103 million for the first nine months of last year. We spent $95 million on our onshore properties, as compared to $34 million in the same period in 2004. Onshore, we have drilled 59 wells, 57 of the 59 wells drilled this year were successful, with only two dry holes.

We spent $66 million to drill 56 development wells, all of which were successful. We spent an additional $14 million for workovers and recompletions and other development costs. We spent $15 million to drill three exploratory wells, only one of which was successful; $59 million was spent on our east Texas drilling program, with $16 million in the Big Sandy well, and the balance of $20 million in south Texas and our other regions. In the last quarter of this year, we planned to spend an additional $25 billion on our drilling program, primarily in our east Texas/north Louisiana region.

Page 14, East Texas/north Louisiana region. Production averaged 44 million cubic feet equivalent per day in this region in the third quarter of 2005, a 17% increase from our second quarter production rate of 38 million cubic feet equivalent per day. Production was impacted slightly by Hurricane Rita, as certain processing plants were shut in in the quarter which reduced third quarter rate by approximately 1 million cubic feet equivalent per day. We drilled 40 successful wells in this region in the first nine months of this year. The wells drilled have an initial average production rate of 1.5 million cubic feet equivalent per day per well. We are currently operating three rigs in this region.

Page 15. Our Cotton Valley drilling program for 2006, the focus of next year's capital program will be a 100-well drilling program in our east Texas and north Louisiana region. This program will primarily target the Cotton Valley formation. The slide on page 15 details how an average well in this program is expected to perform. An average well in this program will cost $1.6 million, and should yield 1.1 BCFE net to our revenue interest, resulting in a finding cost of $1.47 per MCFE. These wells produce approximately one-quarter of a BCF in their first year, 100 wells drilled with an average 75% working interest would cost $120 million and generate 82 BCFE of reserves. The impact of drilling these wells in 2006 would add 9.1 BCFE, or 25 million per day to our 2006 production level. We have six rigs lined up for this program in 2006, and are still trying to secure one more rig.

Page 16, Southeast Texas region. Our production average 17 million cubic feet equivalent per day in 2005's third quarter in this region, which decreased 17% from second quarter production of 21 million cubic feet equivalent per day. Much of the decrease is attributable to Hurricane Rita, as the Indian Springs processing plant was shut in in the quarter which reduced our third quarter rate by 2 million cubic feet equivalent per day. As we reported in the second quarter, the Blackstone Mineral Company Unit B#1 well drilled to test our Big Sandy prospect of the south of Double A wells was not successful and was written off in the second quarter. We did have an additional 2.4 million in costs in this project that we wrote off this quarter.

Page 17: South Texas/other regions. Our production averaged 32 million cubic feet equivalent per day in 2005's third quarter in our south Texas and other regions, which was down 3% from production the second quarter. The decrease is attributable to Hurricanes Katrina and Rita, which impacted our Laurel field in southern Mississippi, as well as some of our south Texas production. The hurricanes reduced our third quarter rate by 1 million cubic feet equivalent per day.

We drilled eight successful wells in our south Texas region in the first nine months of 2005. They have been tested at a per well rate of 4.5 million cubic feet equivalent per day. In the third quarter, we drilled the Clark Sain #14, which had an initial production rate of 7.6 million cubic feet equivalent per day, we have a 20% interest in this well. Our most successful well drilled in south Texas this year was also drilled in the third quarter. The French State #1 was drilled to a depth of 14,458 feet and had an initial production rate of 13.6 million cubic feet equivalent per day.

We drilled nine successful wells and one dry hole in our other regions in the first nine months of 2005. They have been tested at a per well average rate of 1.6 million cubic feet equivalent per day.

Page 18, Bois d'Arc Energy. As was reported earlier today, Bois d'Arc has had excellent drilling results so far this year. Bois d'Arc has drilled 17 offshore wells in the Gulf of Mexico to date in 2005, with a 88% success rate. The most recent well drilled, at Vermilion 12, is still being evaluated. We expect that the reserves added as a result of the 14 successful wells are expected to more than replace Bois d'Arc's production, and significant growth to its reserve base will be added.

The "Paddlefish", "Laker" and "Doc Holiday" prospects wells are the most significant discoveries made this year. Bois d'Arc owns 100% of each of these prospects.

Page 19, Impact of the Hurricanes. Bois d'Arc, along with the majority of the operators in the Gulf of Mexico, were substantially impacted by Hurricanes Katrina and Rita, and other severe weather activity in the Gulf of Mexico that occurred during the third quarter. Certain of our production facilities were damaged during the hurricanes and we estimate the cost of repairs that will not be covered by insurance will be approximately $2 million. We had four drilling rigs under contract in the Gulf of Mexico during the quarter. Nine were damaged by the storms, however, the rigs were idle for a combined 63 days because of the storm activity.

We had to shut in substantially all of our protection for 37 days during the storms. In addition, certain third party pipelines and onshore processing facilities that transported and processed our production were out of service as a result of the hurricanes. Approximately 2.1 BCF, or 30% of our production in the third quarter, was deferred. Since Hurricane Rita, we have restored approximately 57 million cubic feet equivalent per day of our production, which represents 72% of the production level that we had prior to the first hurricane, and hope to have 90% of the production restored by the end of the year. The additional production will be resumed over the next several months, depending on the restoration of third party pipelines and onshore processing facilities.

Page 20, Capitalization. During the third quarter, we reduced our debt by $25 million to $282 million, from $307 million at the end of the second quarter. Our equity has increased to $533 million, for $492 million at the end of the second quarter. Our debt to total book capitalization, which has improved to 35% at the end of the third quarter, as compared to 38% at the end of the second quarter, and in addition, our stake in Bois d'Arc has a market value of around $450 million compared to our $247 million cost basis.

Our hedge positions, Page 21. During the third quarter, we had a mark-to-market loss of $17.8 million. This relates to our hedge position put in place in 2004 after the Ovation acquisition. The spike in gas prices of September 30 resulted in our costless collars to become a liability, as we are not following hedge accounting for these positions.

On slide 21, we show the percent of our gas production which is hedged, and in the fourth quarter about 18% of our gas will be subject to a $10.30 ceiling. Next year, around 15% of our gas is subject to a $9.02 ceiling.

Page 20, The outlook. We expect to spend $120 million on our onshore drilling program this year, which is more than double the $55 million we spent on our onshore drilling program in 2004. The increased investment we are making onshore in east Texas should provide a predictable increase to our onshore production level next year. The 100-well Cotton Valley drilling program we have planned for 2006 will drive production growth next year.

We have 601 low-risk drill sites to support our continued drill big growth in future years. Our investment in Bois d'Arc Energy is performing well, with an outlook for strong reserve and production growth this year. With the common stock offering, and the repayment of our loan from Bois d'Arc, our debt is now only 35% of our total capitalization, giving us a strong balance sheet to support future growth.

With that, I would like to turn it over to Mack Good, our COO, to give you a preview of what our thoughts are on our 2006 drilling program and then we'll open it up for questions. Mack?

Good morning, everyone. Comstock, as Jay mentioned, is currently involved in a very active drilling program in east Texas, we plan to finish the 50-well program as stated. Setting us up for the 100 drilling, 100-well drilling program in east Texas is the anchor to our 2006 CapEx development program. Included in our goal set is our plan to drill 19 wells in south Texas, primarily in the Abaco joint venture area that we've established over the last four years with our partner out of San Antonio, Abaco. We've entered into a new joint venture with Abaco, that gives us substantially higher interest in new properties.

We've targeted Ball Ranch, Javelina fields, the current goal of drilling 16 wells in those properties, and we have three exploration wells that we plan to drill in addition. In southeast Texas, primarily in Double A, as soon as the litigation is finalized, the agreement is finalized with the Alabama Coushatta Indian tribe we plan to drill two wells in Double A on the reservation.

Mississippi is also an exciting area for us next year. We plan to drill 16 wells in Mississippi. We are excited about the opportunity to improve our net oil production profile in that area, and we have substantially greater opportunities to drill even more wells next year if additional rigs are available, and the CapEx resources are, as well.

So to summarize, next year's program is, without a doubt, substantially more aggressive, substantially greater than any program in the Company's history. We've lined up the rigs, we've got the services with our partners, [BJ and Dowal], and Halliburton established, we've arranged for supplies, everything from the drill pipe to the line pipe, to tubing, to casing, et cetera, to set this program on a schedule that we think is both achievable, and we think the numbers that Jay mentioned in his earlier presentation about scheduling on the CapEx is exactly what will happen next year in our drilling program.

The other thing that I want to mention is the people involved here at Comstock in setting this program up have done just an incredible job. We are at a point now where we are actively changing the way we do our business to become more efficient, more streamlined so we can target our goals, track performance, as we've never done before in establishing expectation versus performance and comparisons. So the program next year is setting up quite nicely, and we are excited about it.

One other comment before I turn it over to questions, at the very beginning of this year, you remember, our corporate goal really was to focus in east Texas and north Louisiana. And we announced we would attempt to drill 50 wells. Now, that was more wells than this year, 2005, than the last four years combined that we had drilled in this region. And as we just reported, we've drilled 40 of those wells so far, we've had an IP rate averaging about 1.5 million a day, so we feel comfortable that we will have drilled those 50 wells and, maybe, a few more.

And really, that, what that does, that launches us into the 2006 program which, again, is focused on east Texas/north Louisiana drilling program. We put on the slide 15, we outlined, really, on a micro basis, what an individual well would look like in this 100-well Cotton Valley drilling program. If we are successful in drilling those wells, in this area, then what we think onshore, what we will look like, our production growth in 2006 is expected to increase by approximately 20% to 25% over that of 2005, and really, that's anchored by the 100-well drilling program in east Texas/north Louisiana. In addition to that, what our goal was was to have Mack give you a preview of what would happen in south Texas, the Double A wells area, Mississippi area and some other regions.

You know, there's only two ways to grow a Company. You can either grow it, you add reserves either through the drill bit, which is exploration or really acquisitions, and what we tried to do this year is we tried to configure Comstock, so through Bois d'Arc, we would have great exploration upside in the Gulf, and then onshore, we would manage our growth through drilling, primarily, in east Texas/north Louisiana, and I think this quarter we made good strides towards that. So with that, let me turn it over, Sandra, for questions.

Thank you. We will now begin the question-and-answer session. [OPERATOR INSTRUCTIONS] The first question is from Wayne Andrews from Raymond James. Please go ahead.

Good morning, gentlemen. Maybe this first question for Mack. You mentioned that you do have the six rigs under contract, and I'm sorry, I got on a little late, did you, what's the timing on those? When did you actually take possession of those rigs and really start that second ramp in your activities in east Texas?

Wayne, the short answer is first quarter of next year, early in the first quarter, we should have all six of those rigs running. We expect to have Rig 4 come our way in the next two to three weeks. And there's indications that we may get Rig 5 about that same time frame, but until it's here, I don't count on that. But I do count on Rig 4 before the end of the year, Rig 5 and 6 early in the first quarter, and then Rig 7, we're in negotiations with the vendor to supply Rig 7 late in the first quarter.

Great. And then maybe this one, just a question for Jay. In general, when you talk about your program for next year, it looks like most of these wells are more exploitation type development, so you should feel pretty confident in your ability to achieve the growth rates that you are forecasting for next year. Anything on the exploratory front and what percentage of the total CapEx would you say has an exploratory component for next year? And it's probably lower than you've historically seen.

Wayne, let me answer that real quick. The exploration side of our budget is about 10% to 15% through the JV with Abaco, and that includes some seismic acquisitions that we plan to do with Abaco, and you are right, in terms of the, this year, the exploration budget, obviously, was driven by the Big Sandy project and our involvement with that. Next year, we have multiple exploration opportunities that we didn't have this year, so we're excited about that.

And the other thing, Wayne, remember in east Texas/north Louisiana, as you know, we've been drilling wells there since probably 1991, but we give a statistic that since 1995, we've drilled about 171 wells, and we've had about a 92% success rate over that time period with that amount of wells, and this year, as you know, we've had 100% success there. So we expect that same type of success in the '06 program for the Cotton Valley program.

Excellent. Thank you.

Thank you, Wayne.

The next question is from Ron Mills from Johnson Rice. Please go ahead.

Good morning, guys. With the east Texas/north Louisiana, the Cotton Valley program, are you targeting solely the Cotton Valley? Do you have any Travis Peak opportunities? Can you give us more color on that?

Sure, Ron. We do have, the Cotton Valley is the primary target, in almost all of the fields that we're going to be drilling next year in the east Texas region. But we also have several fields, for example, Logansport, that is Hosston, Rodessa, Pettit, we have some other fields that have, in Texas, with the Travis Peak, and the Pettit, so we have kind of a combination, but the Cotton Valley, by far, is the primary target.

I'm assuming the slide 15 represents solely the Cotton Valley formation? Does that include any of the other formations?

Yes, that's the Cotton Valley pro forma on the average, the average case. The other zones that I mentioned that are behind pipe and those Cotton Valley wells are the upside, and I'd say maybe 15 wells in the east Texas region of the 100 that we planned to drill are Hosston, and/or Travis Peak, and those wells have the same kind of IPs, the same kind of performance distribution.

Would those wells be dually completed or are they just targeting?

No, this would be for later re-completion. They wouldn't be dual.

Okay. And in terms of the six rigs, and, hopefully, the seventh rig getting lined up, have you lined up those rigs on the term contracts, or are they six-month, one-year, two-year contracts?

All of the rigs are on long-term contract. The shortest term is 18 months, longest term is two years.

Okay, and then in terms of the pipeline and what not, have you, in pipe, you suggested that you've lined up most of the materials that you need to execute that program?

Yes, 60% of it has already been bid, and arrangements made and we are in the process of firming up the additional 40%.

Okay. I don't know, Jay, if you want to tackle this one, in 2006 production, you talked about 20% to 25% growth potential. I'm assuming you back off the Bois d'Arc contribution in the first five months of the year, then this year your onshore production averages somewhere in the low 90 million a day range, so would we be correct in suggesting that 2006 production looks like it will be somewhere in the 110 million, 115 million a day range?

Yes, Roland is pulling out his model. That's a conservative growth rate, and I could have given you a little higher, but we said 20% to 25%.

Benchmark for that comparison is we are looking at the onshore production, to onshore, so not really trying to benchmark it against the part that included Bois d'Arc the first five months that included part of the Bois d'Arc production levels, so, you know, this year, we should average in excess of 90 million a day for the onshore production. And, you know, from that base, next year, you know, we would expect that we can grow that 20% to 25%.

One thing we've used, Ron, is that model on page, or slide 15, and in that, I think Roland took a 70% decline from the IP rates in the first year, and then you flattened it out, but we took a very steep decline, that model could have looked a little better, but we think it's a very realistic model. That's why we try to outline it.

Okay. But in, with this year, if you are going to spend, looks like close to $150 million or $155 million ex-acquisitions, to be able to then go to a six or seven rig program and also drill the south Texas, southeast Texas and Mississippi wells, the capital budget, I don't know if you all have officially, or your Board's done anything with this, but you know, it appears that budget would have to increase, you know, would you end up having to spend upwards of $200 million to execute that program?

That's correct, Ron. Next year, we haven't formalized the budget for next year, but it will be in the neighborhood of $200 million.

Right. We said between 180 and 200. We, that's kind of our range right now, and we've not, as a Board, agreed upon that yet.

Okay.

But if you look at the Cotton Valley program, we will spend $120 million just on that program alone. I mean that's what we will spend corporatewide in 2005, we will spend that amount in 2006 just in that one region, so we will spend another $60 million to $80 million in other regions onshore.

Plus we'll have additional costs even in that region for other types of re-completions and other development work.

Right. And that excludes any of the Bois d'Arc ownership.

We we'll come out with an official budget early next month on exactly what we want to earmark for 2006.

Just from a modeling standpoint, Roland, the Bois d'Arc equity income, it's roughly 47% of Bois d'Arc's -- should that be calculated off their after tax income or their pre-tax income?

It's, 48% of their after-tax income. That's what you saw us pick up this quarter, because basically, until Bois d'Arc pays dividends, that's, especially how the accounting works for an equity investee. We really don't know that they will pay dividends. We can't assume that, as far as bringing that over on a pre-tax basis.

And, Mack, you need additional information on both the Laurel and the Coalbed Methane plays in Mississippi and New Mexico, two new areas for you all, I assume came with the EnSight deal?

The first, the Coalbed Methane play in --

San Juan.

-- in the San Juan basin, Cross Timbers and Burlington have drilled 14 wells this year, I believe that's correct, and they have, because of the time of the year, they have shut down their operations there for weather-related reasons, primarily, and the overall performance of that program is pretty much as anticipated. The Mississippi projects that we have on the board are an extension of the established water flood in the Laurel oil field, and drilling for some new undeveloped reservoirs we've identified with the seismic.

Ron, we will have one rig busy all year, and maybe a second rig.

In Mississippi?

Correct,. That's where the 16 wells, the program is, we will have at least one, and may have a second rig busy.

And that rig in Mississippi will be on the ground in one of our locations before the end of this month. So we will start that program this year.

All right. Thanks, guys.

Thanks, Ron.

The next question is from Eric Hagen from First Albany Capital. Please go ahead.

Hey, good morning, gentlemen. Those 600 locations in east Texas, approximately how many of those are unbooked?

Anything on that chart, if it's not labeled is 1-P. So basically there are 200, a little over 200 1-P locations, which means those are proved undeveloped, so they, typically, would be booked.

Okay.

And then the balance, the 400, or so, are in other categories, 2-P, 3-P, probable, possible, so those would not be booked at this time, and then at year end, we will see where we kind of, some of those 2-P's become 1-P's based on this year's drilling program.

But based on your 2006 drilling program, you should convert most of those 2-P and 3-P reserves into proved reserves over the next few years, it sounds like, or based on simple math.

Probably a good percentage of them, depends on if they are direct offsets, that's going to be really the governing factor. If they are a direct offset of something you drill, then you are able to book those as an undevelopable location.

Is there the chance, is that number, that 600, to go up based on drilling on tighter spacing? I know in some areas, they are going from like 80-acre spacing to 40-acre spacing?

That's absolutely correct.

Remember in that chart, in Texas and Louisiana, it's about 470 of the 601 locations.

Okay.

The other locations are Arkansas, Mississippi, Oklahoma, New Mexico.

Okay. All right. So it's split between the various regions. All right. And, Roland, I may have missed this, are there any general guidance on costs for 2006? LOE, DD&A, G&A?

Yes, I think we would see that the cost structures, where it is, the lifting cost is, part of that is governed by what kind of commodity prices are out there, because onshore, a significant component of lifting cost is the severance tax. State severance taxes for offshore, there isn't a lot of that out there. But in a high price environment like the, of course the third quarter, we had $1.26, if gas prices, which are very volatile in the fourth quarter, that could add, with high gas prices, you could add $0.20 to that just to pay the additional severance tax.

So you know, in a high priced environment, we maybe at $1.50 type lifting cost, and more gas price environment, like we had in the third quarter, probably $1.25 to $1.30, you know, kind of what you can expect. Good thing is next year, even though there are some increases in the, out in the field, such as higher power costs, probably higher personnel costs out there, given that we are doing a lot of this drilling in our existing fields, we are going to have some economies of scale and be able to have more production with the same fixed costs in lifting, so I think keeping it in this kind of range, it will be very achievable.

Okay, great. Thanks.

The next question is from Van Levy from Dahlman Rose & Co. Please go ahead.

Good morning, gentlemen. How are you?

Hello, Van.

Good. Exciting program in Cotton Valley. I want to get behind that a little bit. Operating costs and production taxes as a percentage of revenues, for modeling purposes, do you have those numbers?

For the third quarter?

Just in general for a typical, you are laying out typical wells, right? So if I wanted to model this and do some, you know, stress tests, sensitivity, what sort of operating costs would I use there?

Well, again, of course, what happens with these properties, I mean, you could use our base operating cost assumptions of --

$0.80, $0.90?

Right, and we'll have some efficiencies of adding these in existing fields, but just for, $0.80, $0.90, maybe $1.00 at the most for lifting cost.

And production taxes? Is that kind of 5.5%?

5% is a good number to use off whatever commodity price you are using for the severance taxes.

Then the information you give, it looks like about 22% of the reserves are produced in the first year, from a decline standpoint, you know, at the end of the first year, or roughly on average for the first year, is this a 20%, kind of 20%, 25% decline, Mack, in the year two and three?

It goes back to about 8%, once you get past the 70% decline factor, in the first 6 months, then you are at more of a 8% kind of decline for the remaining of the life of that well.

That would be embodied in the first, your first year average, you're giving that average number, right? So that would be embodied within there. So from the base level, you are saying decline it 8? That seems a little low, 8% or 10%. But 8% or 10%, something like that?

Once the well has passed this big 70% type decline, in its first year, then that is the type of rate, decline it has, subsequent to that. On that level.

In terms of booking reserves from your, consulting engineer's standpoint, will it be possible to, I guess, all these wells will be drilled next year, so you should be able to book reserves that you are talking about, and then, which is somewhere around 82 B's, and then with that, would that said up a PUD location that you could book also? So potentially 160 B's there?

Van, you have to keep in mind, we are drilling PUDs that are on the books, converting them to the PDP, and we're setting up the offset wells for, to bring them into the approved categories, so the answer to your question, it depends on how many of those offset wells we convert to the 1-P category.

Okay. So if you did a one-for-one, it would be 80, 82 B's or so, and if not, if you had some issues where you couldn't do an offset, maybe it would be in the whatever, 60, 60 range, something less than that.

It will be attractive. I wish I had a number for you.

Okay. In terms of economics, where does, what kind of rate of return do you get, at say a $10.00 price deck, maybe 8, maybe 7, where does it breakdown in terms of rate of return?

Internally, we, you know, we run all the scenarios versus different cost structures and different decline rates, depending on the fields, et cetera. Depending on which fields you are talking about.

Just the Cotton Valley.

Overall statistically, we are talking north of 40% rate of returns with the $7.00 gas.

Okay.

Probably at the $4.00, you think it's $4.00, $4.50, it's where you start to really break the return where it becomes, under $4.00, it becomes unattractive.

We always at least target, Van, to 20% return.

Right,.

That's kind of the $4.00, $4.50 range.

So you have a lot of head room in terms of prices rolling back and you can still keep this program viable?

Sure, just as, for purposes of this discussion, the one of the things that we do internally on every project is to on a case that determines the flat gas price that would be required to generate a 20% risk rate of return, and that gives us a general indicator where the gas price would have to fall to still give us the 20% rate of return on a risk level.

Okay. First three quarters, your DD&A rate has been about a $1.60, $1.65, is that an indication of where finding costs are going to be this year, or is that just a rough guess and your year end analysis could still move that pretty decently?

Of course, a lot can go into the final finding costs, the timing of when reserves get booked, in east Texas, especially, but apart from that, I think that's a definitely a good base level, a large part of the finding costs this year will be the EnSight acquisition which was in that kind of range, as far as its cost. So I think that's definitely a base part of the finding cost there, and the balance will be, a lot will depend on if, which of the reserves get into the P-1 category in east Texas. It will depend a lot on how the rest of the finding cost comes out. There are not a lot of exploratory adds, we've had a few in south Texas, but not a lot.

I'm surprised you didn't mention it. It looks like your cash to cash returns, if my numbers are correct, are about 620 in cash flow for the third quarter, and with a DD&A rate of $1.64, it's about 300% cash on cash return, which is certainly, you know, off the charts. Even if went up to $2.00 for the year, your DD&A slipped that much. It's bound to go up. It's still great numbers.

If we look at it on a, look at the third quarter, you know, margins that were generated of like you said, the 683 per MCFE, and then comparing that to our historical finding costs, $1.79, it's been the historical average, the last that's been calculated, so that's about a 282% return on that investment.

Right. I'm not very familiar with this Abaco joint venture, can you describe who they are? Is this some sort of joint venture like the, originally with the Bois d'Arc people where they get a piece of the stock, et cetera?

This is a small prospect generating group out of San Antonio that we've interacted with, primarily, in Kennedy County, Ball Ranch field over the last three years, and last year, we participated at a 50% working interest level in the further development of Javelina field in Hidalgo County, also an Abaco venture, and recently, we signatured a new agreement with Abaco to allow Comstock to participate at a 50% interest in all subsequent proposals made by Abaco, and there's a number of those on the board that we are currently evaluating.

What do they get for letting you do that?

They get a carry on the first well to the tanks, and they participate after payout of the project at a 10% working interest.

And who are the principles of Abaco?

That's Eric Hanson is the founder, the principal.

Okay. Great, and last thing, mechanical question, oil and gas prices pre-hedged? Do you have those, Roland?

That's going to be what we reported, 828, and the 5257. The, we really don't have any hedges that we count for under hedge accounting. The positions, the costless collars are all accounted for with the marked-to-market.

So you didn't have any cash loss on that this quarter?

Well, as far as settling those positions, we did have $140,000 cash expenditures related to that costless collars.

Great, thanks, guys.

Thank you, Van.

The next question is from Rehan Rashid from FBR. Please go ahead.

Good morning, gentlemen. Mack, not to beat this [INAUDIBLE] program to death, but it's definitely important and execution is key. Could you, you've lined up the rigs, that's great, you're working on the services, that's great. Tell us in terms of, call it management by exception, you are going to go from 44 million a day in the third quarter to 25 more next year, average. That means you probably should exit next year on 80, 85 million a day. What issues could be caused, could cause bottlenecks in terms of bringing production on line? You need to put, to head into pressure -- compression curve, or what would keep you awake at night throughout next year to deliver on this program?

You are exactly right, scheduling and execution are the keys. The bottlenecks are, or will be what they currently are that we face in the gatherers, the purchasers are working with us to resolve in Comstock's marketing department, and that is the take-away rates from some of these fields are currently limited by the size of the pipes and the compression that's in place. The purchasers are, obviously, incentivized to improve their systems. We are not the only operator in east Texas that have plans to ramp up their programs for next year, and some of the purchasers now are installing different compression set ups, and looping pipes to be able to increase the take away rates from a number of these fields.

We think the timing is good, because, as I mentioned earlier, the ramp-up in Comstock's program is really going to start deep in the first quarter.

That's when all of our rigs will be in play, and, we think, given the information, the feedback we've been getting from the purchasers from these various fields that we'll be active in, that they will have their new compression, their new set-ups in place at that time, so, but will we have problems? Certainly. There are always problems. We think we have a good game plan, though, going forward. A number of the fields, the activity level to improve the infrastructure is already in play.

So should we presume, Roland, that some of this is built into the cushion for next year's production contribution from this area? The possibility of delays, and compression, everything else?

That's why when you look -- yes, when you look at the program and look at what's capable, I think it ultimately is capable of doing that, but you can't expect maximum performance right on top of that, so, we've also looked at, even with this new production, we've applied some pretty conservative high decline rates to our existing production, which may be more than what that will happen to.

It's, the cushion is there basically was the question?

Right.

Mack, would I be too off base, when I think about the exit rate in this area for next year, should be in this 80 to 85 million a day, kind of number?

If we can execute the program as we have, that we have in place, yes, I think your number is pretty much in the ballpark.

And not to get too far ahead of ourselves, but there is no reason why we couldn't have 100, 120-well program in '07?

Correct.

Okay. Okay. Lastly, Jay, if I run 20%, 25% growth for next year, use some semblance of a current commodity price stack, it cost you $300 million in after-tax operating cash flows, CapEx 200 million, still leaves a lot of room, given the graduation disparity here, any thoughts regarding buy-backs or stock buy-backs? What's the plan for this excess cash flow that could show up pretty soon?

One of three things, Rehan, one, we could use part of that $100 million to pay down any bank debt that we might have. Although, I think, in the fourth quarter, we are going to pay that down materially again as we did in the third quarter. I think this, the second thing, you can look at any acquisitions out there, but you have to balance that against where Comstock stock is trading at, and you've got to look on a per MCFE basis. Is it wiser to buy our stock back or to try to buy something else? And I think, you know, we are going to address that at the December Board meeting of Comstock, and we probably will put back in some kind of buy-back provision, so now we'll look at that, I think we should. We are in the position to look at that now.

Okay. And again, going towards more of a going concern thought process, good program for next year, but from an organic basis, what, infrastructure and CapEx can sustain a higher activity level, what else are we trying to do from an organic growth standpoint so growth continues beyond '06 into '07 and '08. Any thoughts about going to different areas and where you guys are right now, whether that be the Appalachians, the Rockies, or some other place, or this is where you're going to stay?

Yes, Mack is nodding his head north and south. We always look for other regions, Rehan. I think what you'll see, our goal in '05 was to demonstrate we could drill the 50 wells. This was a pretty big stretch versus what we had drilled in that area, and now that we are comfortable with that, I think '06 is not a big a stretch as '05, and then you go to '07, and again, we've got over 600 wells, and, as we stated earlier, as we drill a lot of these locations, we should add new locations, all that is based upon price sensitivity, but you know, given where prices are today, we will add more locations, so the goal in '07 would be 150 wells in east Texas.

I think we'll continue to increase the amount of money we spent in south Texas, and I believe that Mississippi will be a new kind of important core area for us as we have a rig or two busy all of '06, and probably going into '07, and we will continue to look at expanding our regions. As we've always done for the last 18 years as you've seen us.

On Mississippi, the water flood, Mack, are we seeing, what kind of evolution do you see to that in terms of production impact? Are you seeing the impact of water floods coming through now or expecting it in six months? I'm not recollecting the program in too much detail.

We have an active water flood study that we are participating in. We anticipate that that evaluation will firm up the particular areas that, where we can extend the water flood and improve performance sweep efficiencies, et cetera, so part of the drilling program for next year will be drilling additional withdrawal wells and injector well for the Rodessa water flood. There are also other reservoirs that have not been water flooded in the Laurel oil field and we are also taking a hard look at that.

To go back to your other question in terms of looking at new areas, of course, we're doing that all the time, but there's some things that we are looking at internally here that are quite exciting, and will allow us to consider participating and, perhaps, operating in new areas for us that will, like Jay mentioned earlier, add to core regions, areas that we're familiar with, but enough said about that.

Rehan, on to one thing if you go back to the history of Comstock, just because we can drill, we think we can drill 100 wells in '06, if that's all we did in '06, and didn't do something else, I think we would be disappointed in ourselves. Example, in 2004, we started creating the value of the Bois d'Arc IPO, and we executed that in '05, we bought Ovation at the latter part of '04, bought EnSight in early '05, we raised the equity, we issued, we did the secondary offering, we did a bunch of things in '05 that if you would had taken November conference call of '04, we could not have told you that we would do those things.

I mean, I think, you bank on management always trying to stretch the growth curve, but do it cautiously, and I think we are pretty comfortable, I know Mack has a lot of hard work, but we are comfortable that we can drill the 100 wells in east Texas, north Louisiana, so now, it's our view of what else can we be doing? And we do have right now, looks like we have an additional $100 million of free cash flow over and above a $200 million CapEx budget, and we would not hesitate to buy our own stock back if Comstock didn't perform with the peers, or we would do something to create value with those dollars, but you, you know, if you ever thought we wouldn't do that, then we're not a good story for you to look at. Because we will always do that.

Absolutely, just kind of, buy backs makes sense at these levels. I wanted to hear what your opinion was on that. Thank you.

You bet, thank you, Rehan.

Ron Mills from Johnson Rice is back on line with a follow-up question. Please go ahead.

Roland, can you just run through your hedging position in terms of volumes and pricing?

Sure, if you look at, I don't know if you looked at the slide, there's a little slide that -- that helps you out there. It's a little more, this one is more simplistic and it's presented on the NYMEX basis, but part of this position is actually Houston shift channel hedge, and it's almost half and it's adjusted, Houston shift channel price is a little lower, but then it matches better with the actual, with that index price, which is lower.

But basically, you can see it's about roughly for next year, about 15% of the gas production. We'll be subject to the ceiling, which will be 902, so roughly, to the extent that NYMEX prices over 902, we will will be paying on these costless collars. We are not accounting for them as hedges, so that's why the whole marked-to-market losses already has been provided for in this quarter, and that number changes based on the fair market value of this position.

Ron, what's strange about this slide on 21, and I know Van Levy and Wayne Andrews would agree, and Rehan Rashid, we, historically, never hedge, as you know that, you've heard us say that a million times. I think you'd have to break Roland's body in half to make him hedge, but when we bought Ovation, we did hedge for a reason, and when we implemented the first 50-well programs in east Texas, and that's, that 15 million day we hedge, that's what shows up on page 21, which is a very unusual slide for Comstock, and we thought it would be costless event, and it's a very costful event now.

Yes, it's a wide range, but since the prices are now over this 902 level for next year, at least for now, it comes into play where this position has been around for a while, but if it's so wide before that it was almost ignored with the 450 floor and $10.00 ceiling this year.

But, basically,, you had a, it's 15 million a day hedge between 4.5 and 1030 in the fourth quarter, and same volumes next year between 4.5 and 902?

Right, the same volumes, the only reason the percentages are a little lower is because of our forecast it will be higher. But the exact same positions that we're two years, and they were in place for all of '05, all of '06, and they are running off, the 19% that was of our production in the third quarter, only real cash we paid out was $140,000 to close those out. In the fourth quarter, we will pay out substantially more than that, probably $3 million or $4 million, depending on how prices fall out because they have been so high, at least for the first two months.

Okay, with G&A, it was lower than I thought in the third quarter. Is a more normalized level for you all, including your non-cash expenses, should it be close to that $3.5 million? Is that --

I'm using $4 million, a quarter, you know, and you get into '06. As the Company is expanding its, technical, we've added a lot of people this year, on the technical side, and the the cost of technical people are also going up.

And, Ron, hopefully we will offset that by not drilling a $16 million dry hole at Big Sandy.

[LAUGHTER] Exactly. And then in terms of deferred taxes, lastly, given the kind of profitability outlook, are you still expecting to be able to defer roughly 90% of your taxes, just, particularly given the ramp-up in activities?

With the higher prices, you know, that you have to maybe come back and back off of that, maybe get down to 80%, or 75% because what happens is the profits are, if they out strip so much of our cash flow like is indicated by looking at these high prices versus the capital budget, that's an indication that the deferred tax percentage is going to have to decrease because of the extent that we, because we are going to be generating this excess cash flow and not putting it back in the ground. So I think, you know, what you are, what you'll see is that probably that percentage needs to be looked at more like, you know, 75% next year as long as you are using these higher prices, and if prices pull back then that number can come back, also.

Okay. Thanks, guys.

Ron, the other thing that either you or, I think, Van asked, on finding costs, remember we should have some significant discoveries from the Bois d'Arc side with low finding costs there, too. So I mean we do own 48% of that Company.

Right.

You have to kind of add that in somewhere.

Okay. Thanks.

There are no further questions at this time.

All right, again, we're grateful that you called in and asked questions and, you know, we plan on having a good fourth quarter, and we will report to you after that. Thank you.

Thank you. Ladies and gentlemen, this concludes today's teleconference, thank you for participating, you may now disconnect.