Comstock Resources Inc (CRK) 2005 Q4 法說會逐字稿

Good morning, ladies and gentlemen and welcome to the year-end 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 this conference is being recorded. I would now like to turn the call over to Mr. Jay Allison. Mr. Allison, you may begin.

Mary, thank you. Welcome, everyone. Welcome to Comstock Resources' fourth-quarter 2005 financial 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'll find a presentation entitled Fourth 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 fourth-quarter 2005 and annual financial and operating results as well as results of our 2005 drilling program.

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

Slide 2. Strong oil and gas prices and increasing production from our own onshore properties results in record high financial results for the fourth quarter and the year in 2005. Our revenues reached $93 million and we generated EBITDAX of $73 million and operating cash flow of $69 million. We also generated a profit of $35 million or $0.82 per share excluding the unrealized marked-to-market gain on our hedge position, which increased our reported income for the quarter to $41 million or $0.96 per share. For all of 2005, we had revenues of $303 million, EBITDAX of $241 million, cash flow of $216 million and earnings of $91 million or $2.21 per share excluding special items. Apart from the Big Sandy, our drilling program has been successful with a 97% success rate, having drilled 75 wells with only two dry holes.

We closed three major transactions in 2005 that have transformed the Company and positioned us for future growth. The $191.6 million EnSight acquisition added 18 million cubic feet equivalent per day to our production and added 424 drill sites to our own onshore drilling inventory. To strengthen our balance sheet, we sold 4.5 million shares of Comstock's stock at $27.50 per share in a public offering.

On May 11, Bois d'Arc closed its initial public offering at $13 per share and is now trading on the New York Stock Exchange.

Page 3. Since we no longer reflect our share of Bois d'Arc Energy since we began using equity accounting, we compare our onshore production on Slide 3. Our onshore production averaged 101 million cubic feet equivalent per day in the fourth quarter, which is an increase of 23% from the fourth quarter of 2004. For the year, our production averaged 91 million cubic feet equivalent per day in 2005, a 14% increase from the 79 million cubic feet equivalent per day we averaged in 2004. Our East Texas/North Louisiana region averaged 49 million cubic feet equivalent per day. Our Southeast Texas region averaged 19 million cubic feet equivalent per day. And our South Texas and Others region averaged 33 million cubic feet equivalent per day during the fourth quarter of 2005.

In 2006, we expect our onshore production to increase to 110 to 115 million cubic feet equivalent per day or 20 to 25% over 2005 driven by the increased drilling activity in our East Texas/North Louisiana region.

Our average oil price. Oil prices increased substantially in 2005 driven by increases in demand and supply concerns after the hurricanes. Our average oil price increased 7% in the fourth quarter of 2005 to $50.17 per barrel as compared to $47.06 per barrel in the fourth quarter of 2004. For the year, our average oil price increased 23% to $49.01 from $39.86 in 2004.

Average gas price. Natural gas prices surged after the hurricanes hit. Our average gas price increased 56% in the fourth quarter of 2005 to $10.38 per Mcf as compared to $6.66 per Mcf in the fourth quarter of 2004. For the year, our average gas price increased 31% to $7.83 from $5.98 in 2004. Our differentials from the NYMEX Henry Hub price widened significantly in the fourth quarter from their historical relationship. In the fourth quarter, the NYMEX Henry Hub price averaged $12.97, which was $2.59 higher than our average realized price. Historically, our average gas price is within $0.10 of the NYMEX benchmark.

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. In the fourth quarter 2005, our oil and gas sales increased to $116 million, which represented a 63% increase from 2004's fourth quarter oil and gas sales of $71 million. For the year, our sales increased 38% to $361 million as compared to 2004 sales of $261 million.

EBITDAX. Our earnings before interest, taxes, depreciation, amortization and exploration expense and other non-cash expenses increased 33% in the fourth quarter of 2005 to $73 million as compared to $55 million in the fourth quarter of 2004. For the year, our EBITDAX increased 19% to 241 million as compared to EBITDAX in 2004 of 203 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 the 10.

Cash flow. Our cash flow from operations increased 45% in the fourth quarter of 2005 to $69 million as compared to cash flow of $48 million for 2004's fourth quarter. For the year, our cash flow increased 23% to $216 million as compared to $176 million in 2004. Using the equity method, we did not include $39 million in operating cash flow related to our share of Bois d'Arc's operations after May the 10.

Earnings. Excluding the marked-to-market gain from our derivatives, we reported net income of $35 million or $0.82 per share for the fourth quarter of 2005 as compared to net income of $16 million in the fourth quarter of 2004 or $0.43 per share. Excluding the derivatives loss and the loss for the conversion of Bois d'Arc to a taxable corporation, we had net income of $91 million or $2.21 per share for the year in 2005 as compared to net income of $60 million or $1.66 per share in 2004, excluding the loss on early retirement of debt.

Fourth-quarter cost per Mcfe. With rising oil and gas prices, our unit costs have been increasing also. Our lifting costs per Mcfe produced increased $0.12 in the fourth quarter of 2005 to $1.52 as compared to 140 in the fourth quarter of 2004. Higher production taxes and higher ad valorem taxes due to higher gas prices account for much of the increase. Our G&A per Mcfe excluding stock-based compensation decreased by $0.01 in the fourth quarter of 2005 to $0.26 as compared to $0.27 per Mcfe in 2004's fourth quarter. Our depreciation, depletion and amortization per Mcfe produced increased $0.13 in the fourth quarter of 2005 to $1.73 per Mcfe as compared to $1.60 per Mcfe in 2004's fourth quarter.

2005 cost per Mcfe. Our lifting costs per Mcfe produced in 2005 increased $0.10 to $1.32 as compared to $1.22 in 2004. Our G&A per Mcfe, excluding stock-based compensation, increased $0.09 in 2005 to $0.29 as compared to $0.20 per Mcfe in 2004. Our depreciation, depletion and amortization per Mcfe produced increased $0.18 in 2005 to $1.64 per Mcfe as compared to $1.46 per Mcfe in 2004.

Capitalization, Slide 12. During the fourth quarter, we reduced our debt by $39 million to $243 million from $282 million at the end of the third quarter. Our equity increased by $50 million to $583 million from $533 million at the end of the third quarter. Our debt to total book capitalization has improved to 29% at the end of the year as compared to 35% at the end of the third quarter. This ratio shows a dramatic improvement since the end of 2004 when it was 53%. In addition, our stake in Bois d'Arc has a market value of almost $500 million as compared to our $252 million cost basis.

Onshore drilling expenditures. On slight 13, we break out our onshore drilling expenditures by region. We spent $122 million in 2005 on our onshore properties as compared to the $55 million that we spent in 2004. Seventy-three of the 75 wells drilled this year were successful with only two dry holes. We spent $87 million to drill 72 development wells, all of which were successful. We spent an additional $20 million for workovers and recompletions and other development costs. We spent $15 million to drill three exploratory wells, only one of which was successful. $81 million was spent on our East Texas drilling program, $16 million was spent on the Big Sandy well and the balance of $25 million in South Texas and our Other Regions.

Slide 14. East Texas/North Louisiana region. Production averaged 49 million cubic feet equivalent per day in our East Texas/North Louisiana region in the fourth quarter of 2005, which increased 11% from our third-quarter production rate of 44 million cubic feet equivalent per day. We drilled 52 successful wells, 40.2 net wells, in this region in 2005. The wells drilled had an initial average production rate of 1.6 million cubic feet equivalent per day per well. We currently have seven rigs under contract for our 96-well drilling program in this region for this year.

Slide 15. Southeast Texas region. Our production averaged 19 million cubic feet equivalent per day in 2005's fourth quarter in our Southeast Texas region, which increased 6% from our third-quarter production of 17 million cubic feet equivalent per day. As we reported in the second quarter, the Blackstone Mineral Unit B No. 1 well drilled to test our Big Sandy Prospect in the south of the Double A Wells field was not successful and was written off earlier in the year. In 2006, we plan to drill two development wells in the Double A Wells field to offset some of the production decline that we have experienced in this region.

Slide 16. South Texas/Other regions. Our production averaged 33 million cubic feet equivalent per day in the fourth quarter in our South Texas and Other regions, which was up 5% from production in the third quarter of 32 million cubic feet equivalent per day. We drilled 10 successful wells, 3.5 net, in our South Texas region in 2005. They have been tested at a per-well average rate of 6.3 million cubic feet equivalent per day. These wells were drilled in our Ball Ranch, Javelina and J.C. Martin fields. We drilled 11 successful wells, five net wells and one dry hole in our Other regions during 2005. Six of the wells drilled were successful coalbed methane wells in the San Juan basin in New Mexico. We drilled two successful wells in our Laurel field in South Mississippi. The remaining three successful wells were drilled in Arkansas and Oklahoma.

Slide 17, Bois d'Arc Energy. Our Gulf of Mexico operations are now reflected in our 48% ownership in Bois d'Arc Energy. Despite the setback to production operations caused by the hurricanes, Bois d'Arc had a successful drilling program in 2005. In 2005, Bois d'Arc drilled 19 successful wells out of a total of 22 wells drilled with three dry holes. Eighteen of the successful wells were in the Gulf of Mexico and one was in South Texas. The discoveries at Ship Shoal Block 111, which proved at the Laker Prospect; the South Timbalier Block 75 discovery, which tested the Doc Holiday Prospect; the Ship Shoal Block 56 discovery and the Ship Shoal Block 92 Paddlefish well were the larger reserve discoveries in 2005.

Bois d'Arc's 2005 exploration activities added approximately 107 Bcfe of new, proved and probable oil and natural gas reserves.

Tab 18, Bois d'Arc's exploratory inventory. In addition to its property base, Bois d'Arc has substantial upside due to their extensive multi-year inventory of exploration prospects. Bois d'Arc has 47 prospects identified with unrisked reserve potential of 1.3 Tcfe as outlined on Slide 18.

Slide 19. Proved oil and gas reserves. At the end of 2005, the total proved oil and natural gas reserves attributable to our onshore properties are estimated at 432 Bcf of natural gas and 12 million barrels of crude oil or 505 Bcfe as compared to our onshore reserves at the end of 2004 of 446 Bcfe. Our reserves are 86% natural gas and 14% oil. Fifty-nine percent of our reserves are developed and 41% are undeveloped. We operate 76% of our proved reserve base. The present value using a 10% discount rate of the future net cash flows for income taxes of our proved reserve is approximately $1.6 billion using our actual December 31, 2005 oil and natural gas prices of $49.17 per barrel for oil and $8.27 per Mcf for natural gas.

In 2005, we were able to replace 277% of our 2005's onshore production. Our 2005 exploration, development and acquisition activities added approximately 140 Bcfe of new, proved oil and natural gas reserves. Acquisitions accounted for 122 Bcfe of the additions with discoveries and extensions adding 18 Bcfe. These reserve gains were partially offset by 48 Bcfe of performance and related downward revisions on last year's reserve base. These revisions were primarily related to undeveloped reserves in Kentucky where drilling activities under a farmout agreement has been unsuccessful and to the Double A Wells field, where production declines that we had in 2005 have been higher than what we anticipated last year.

In addition to the proved reserves relating to onshore properties, we have 155 Bcfe of proved reserves in the Gulf of Mexico attributed to our 48% equity ownership of Bois d'Arc Energy as of December 31 of 2005. Such reserves have a present value using a 10% discount of the future net cash flow before income taxes of $925 million.

Much of our spending for exploration and development activity in 2005 related to drilling proved, undeveloped wells in the East Texas, North Louisiana region, which were successful but did not result in significant proved reserve additions. At the end of 2005, we estimate that we have 156 proved, undeveloped, operated drilling locations in these regions and an additional 252 probable and possible operated drilling locations in this region. The net probable and possible reserves attributable to our operated probable and possible locations are estimated at 120 Bcfe. Much of our 2006 activities will target converting these reserves to proved.

Slide 20, our 2006 drilling program. This year, we have budgeted to spend $200 million on our onshore properties. This budget represents a 64% increase over our spending in 2005 of $122 million. Development projects make up $179 million of the budget -- of the 2006 budget and $21 million of the budget is allocated to exploration activities. We plan to drill approximately 149 wells in 2006 or 102.5 net wells. Our East Texas/North Louisiana operating region will receive the largest portion of our 2006 budget with forecasted expenditures of $134 million. We plan to drill 96 development wells in this region in 2006 or 74.2 net wells. We expect to spend $28 million in our South Texas region to drill 21 wells in 2006 or 6.5 net wells. We have budgeted a total of $30 million for our Mississippi properties, which were acquired in May of 2005, where we plan to drill 16 wells or 15.4 net wells. The remaining $8 million will be spent on our properties and other regions.

We currently have eight drilling rigs contracted for our operated drilling activities in 2006. The increased drilling program will be the primary driver of the 20 plus percent production growth that we expect to have in 2006. Given the current strong natural gas prices, we expect y the operating cash flow that we generate will be able to fund this program in 2006.

Our hedge position, Slide 21. During the third quarter, we had a marked-to-market loss of $17.8 million and in the fourth quarter, we had a gain of $9.8 million to reverse part of the third-quarter loss. Our balance sheet at the end of 2005 still includes a liability of $11.2 million for the unrealized loss of these positions. This relates to our hedge position put in place in 2004 after the Ovation acquisition, which is detailed on Slide 21. The spike in gas prices in 2005 resulted in our costless collars becoming a significant liability, as we're not following hedge accounting for these positions. In the fourth quarter, we paid out $2.4 million on these positions as gas prices exceeded the ceiling price of $10.30. In 2006, around 15% of our gas is subject to a $9.02 ceiling.

Our 2006 outlook, Tab 22. Looking at 2006, we're very excited about the prospects for Comstock. We expect to spend $200 million on our onshore drilling program this year, which is 64% increase from the $122 million that we spent on our onshore drilling program in 2005. The 96 Cotton Valley well drilling program we had planned for 2006 will drive production growth this year. We have 408 operated low-risk drill sites to support our continued drill bit growth in future years. Our investment in Bois d'Arc Energy is performing well with an outlook for strong reserves in production growth this year.

With a common stock offering and the repayment of our loan from Bois d'Arc, our debt is now only 29% of our total capitalization, giving us a strong balance sheet to support future growth.

With that, Mary, let me open it up for questions please.

(OPERATOR INSTRUCTIONS). Larry Busnardo, Petrie Parkman.

In regards to the East Texas drilling program, you talk about having a set of rigs under contract. How many are currently operating in the field and then can you basically just lay out when you expect to have all seven operational? Hello?

Larry, can you hear me? What I'd like to do with that question is I'm going to turn it over to Mack Good. He will tell you we have four rigs operating right now but he will tell you when we expect to move the other rigs on. And I would like for him to go over a little bit of the program with you, if that's okay.

That's perfect, thanks.

Good. Larry, this is Mack Good. Good morning to you. We have got four drilling rigs, as Jay mentioned, in East Texas, North Louisiana working. We expect to receive the other three rigs in late March/early April to start that part of the program and we have an additional one rig working in Mississippi. We have all but two of the rigs on two-year contracts and the two that are not on two-year contracts are on 18-month contracts. So, we're pretty well set on the drilling rigs necessary to perform the program that we have outlined.

How about also I guess in regards to that program, services lined up, completion, steel, things like that, do you have all that already lined up and ready to go?

Yes, we have alliances structured with major vendors to provide the services necessary to complete the wells. We have 80% of our casing and tubing ready -- prepurchased; it's pay as you go but we are on a delivery status for that pipe. We have the necessary contract personnel to do everything from the land work to location build to infrastructure installation, as of course we have also got the drilling rigs under contract, as I mentioned.

I think in the past, Jay had talked about six rigs would be enough to complete that 100-well program and if you get the seventh, obviously you get there a little quicker, you may be able to drill a little bit more. Are you set up on 96 wells or could you potentially drill more? Does that rig go somewhere else? Can you talk about that a little bit?

The six rig estimate was based on delivery of all of the rigs a little earlier in the year and we're getting those rigs. We have a new rig that is currently under construction. That one will be delivered in the first or second week of April. All the other rigs will be on the ground drilling for us by the end of March. That's the anticipation, the latest information we have.

So, the bottom line is, yes, of course we hope to be able to drill more if our budget allows. And in addition, our budget accommodates some delays in drilling service due to problems that we have historically had. So we feel pretty confident that the drilling program we've put in place here, the budget is doable because we've factored in some of the delays that we normally see.

Larry, one thing I think we have what, four or five service companies with the seven rigs. How many different service companies? Drilling companies?

Currently we have four.

We have four different drilling contractors with the seven rigs. Kind of split it out a little bit.

The other thing I want Mack to go over, it may or may not be a question that somebody has in a moment -- our goal in '05 if you remember in August of '04, we said we want to drill 50 wells in '05 and then 50 wells in '06 in the Cotton Valley program. Well, the goal in '05, that is four times more wells than we had ever drilled in the Cotton Valley in any given year. So really what Mack did is he wanted to achieve the goal of drilling those wells and we did do that; I think we drilled 52 wells.

But I think at the end of the year, I looked at it and we all looked at it and said we didn't drill any wells that weren't legacy wells. I mean these are wells at locations that we had bought probably ten years ago and we didn't really step out and prove up any additional reserves.

That's the one thing that will change this year. We were pleased that we could drill the number of wells with the success rate at 100%. We didn't expect that. We expected 92, 96%. We probably in hindsight, Larry, and we should've spread out and drilled them in [a little] different areas, but if you remember, rigs were hard to get, tubulars were hard to get and the goal was just to drill the wells. And we did do that but I think you're going to see that expand this year.

And one of our fears which was last year is could we really drill the 50 wells in that area because that again was four times more than we had ever drilled. And we're comfortable with that and now we know we can drill the 100.

So now I think you will see our operations group really kind of blossom in the fact that some of these wells will be drill to prove up some offset locations. And Mack may want to go over that with you too.

Yes, the program structure in '05 was to -- or involved drilling, as Jay mentioned, legacy well locations. And what we mean by that is that those wells were already on our reserve base. They were PUDs that were already booked. So it was strictly an exploitation and continued development program. And a number of things grew out of that program that gives us great confidence to initiate and execute the '06 program. Of course, the first and foremost is being able to reduce the drill time. Some of you may have heard me mention that in previous conference calls that we have reduced our drill time in the Cotton Valley to around 15.5 days to TD. Prior to the '05 program, we were taking about 24 days or so to TD, a typical Cotton Valley well. And at the escalating dayrates, that's a significant achievement.

And in addition to that, that effort, we have also compressed the completion time on the wells and built the alliances that I mentioned earlier with the various vendors that allows us to establish the '06 program goal. But the point is that we drilled PUDs that were already on the books.

In the FY '06 drilling program, we're targeting a number of locations that will, if successful, prove up the probable and possible locations and we're excited about that opportunity but we are very confident in the program that we've put in place. We have targeted 15 different fields for the majority of the drilling program throughout East Texas and Louisiana and four of those fields hold great promise for additional conversions from probable, possible into the proved category.

Great, thanks for the update. Jay, one last one for you. Given where the stock is currently trading and obviously there has been a bit of a meltdown here over the last couple of weeks, your stock at least the onshore assets are trading fairly cheap out there. What do you think you have to do in order to get that side of it up? Because if you look at it on price to cash flow and ground valuation, it looks cheap on all those. Do you think it's just a matter of going through, completing this East Texas program because that's what everyone is betting on right now?

I think there's probably three answers to that, Larry. I think one, you need to see at least maybe one or two quarters, I'd say two quarters of performance. We've continued to show production growth but we hadn't added reserves and I think you've got to continue to see the production growth and you've got to see that we can drill all these wells. I think that's number one because out of the $200 million, almost 140 million is focused on East Texas and it's not a matter of success. You know we always have 90 plus percent success rate.

It's can we continue to increase the production and I think the market rewards you for that. And of course at year end, will you blend it in and not just fill in two fields because the majority of the drilling last year was in two fields and this year it will be in 15 different fields.

I think the second thing, we only drilled one well and all of the EnSight properties last year. So we spent seven or eight months really continuing to evaluate that. You will see the EnSight acquisition, the $191 million, I think blossom in '06. We didn't say that it would blossom last year. We did think early on we would drill ten wells. We actually drilled only one, so I think you'll see that.

I think the third thing is all these E&P companies have pulled back in their price. We have never had a stock buyback program. I know after 9/11, we bought about $5 million of shares but we do have a $25 million buyback program and if we needed to increase that, we could probably increase that a little bit.

So I think right now, as far as the best place to spend our money, I mean the stock is 26, 27. Two weeks ago, it was almost 34. All these companies have pulled back materially. I think that's probably a good place to spend our money right now. And we will have to implement our plan and I think the market has accepted the plan.

I think the question is, can we add new reserves. And historically we have been able to do that. I know the last seven years we have averaged about 108% organic growth as far as reserve replacement. Last year, we did have reserve revisions.

We got rid of Kentucky for the most part. That was something that was lingering forever and ever when we bought DevX. We did try to bring a third party into develop it; they spent 2 or $3 million; it didn't work. Our goal is to sell what we own this year, what we had written off. So I think you'll see that as over with.

We did drill the big dry hole, the Big Sandy last year. That by no means was a positive. I mean it was an 8 or $9 million well that turned out to be a 16 to 17 million dry hole. Historically we have had an 86% success rate in Double A, and that was a bad well. We didn't advertise it as a well that had over 20% success rate and we weren't successful. I think we were very forthright with everybody on that. I don't think the market hurt us for that but if you look at a bottom line number, that's a lot of money. We're going to spread that out over probably 14 or 15 wells this year and I think we will get more bang for our box.

And I think the other thing is you have to look at Bois d'Arc. I mean the market recently has not given us any value for our ownership in Bois d'Arc. That's anywhere from 500 to $600 million of value. That's 10, 11, $12 per share. I think that's the real question right there, will the market give us a value for that? So we're focused on that and that's what we're doing.

Great, thanks for the comments.

Wayne Andrews, Raymond James.

I wanted to follow up a little bit on the East Texas, which, Cotton Valley, Travis Peak trend, which has become an area of significant interest now. We have seen a number of operators move in there. It might be worthwhile for you to explain a little bit about your long history there and the fact that there used to be sweet spots in these fields or in this area, which were originally your fields and now it seems like everybody seems to be filling in. And every acre looks somewhat productive there but by legacy of your historical field position there, maybe your wells are potentially IP-ing and have larger reserve potential than some of the other activity. I was wondering maybe you or Mack might be able to comment on that.

Let me kind of go over the history, Wayne. It's going to date you because that means you have known us for ten years or longer. That's a good thing though. We want every analyst to know us for a long time because I think that that's what you state your reputation on.

In 1991, we bought you know a third or half of the production of what was Goodrich Petroleum at the time. They were a private company, does East Texas, Northeast Louisiana. Then in 1995, [Somad] had a divestiture of the majority of their East Texas/North Louisiana fields. We paid $50 million back when gas was about $1.05 and you could buy it for maybe $0.20, $0.30 in the ground. We bought over 330 wells in 1995. At that time, that 50 million acquisition, which is 11 years ago, it doubled the size of Comstock.

The reason we went to East Texas/North Louisiana was one, we didn't have a lot of money; we probably didn't have hardly any and so you had to go to a place where the production was predictable because if it was predictable then it was probably bankable. Or at least the commercial banks would tell you how much equity you needed and they told us that and we found the equity and we bought some out of their reserve base. And then we continued to add to that over the years. We added to it with several acquisitions that were 20 and $30 million and we added to it with the DevX acquisition. And then we added to it most recently with EnSight, which is the March '05 announcement and we closed it in May, that gave us an additional 400 plus locations.

The great thing about Comstock being in that area for ten to twelve, thirteen plus years is that our cost basis on all the properties except for EnSight, which is $1.60 per Mcfe, our cost basis was very nominal. It was again we bought reserves for $0.20 and $0.30 in the ground, not $3 in the ground for P1, P2, P3 type reserves.

That's why when we went in and said how many -- what we did in 2004 is we tried to get rid of our expensive bonds, which are 11.25% to save us about $12 million a year in interest expense. When we got rid of that, then we really had spent most of our money, Wayne, as you remember, developing our relationship with Bois d'Arc. And that exploration, development exploitation program was so successful, they went public. When they went public, one of the reasons it was beneficial to Comstock, it captured that value in an exploration program that was controlled by the two men that had created the majority of that value but equally as important, it allowed Comstock to get back to growing its onshore reserves and so Mack, who was VP of Operations, was promoted to COO and he grew up in the East Texas/North Louisiana area. And we said Mack, how many acres do we have. And that's when -- I remember one time when I was talking to you, Wayne, we said we have 12,000 undeveloped acres and that was before we bought EnSight. And on 40-acre, 80-acre spacing, we had anywhere from 152 to maybe 300 drill sites. So that's when we announced in August of '04 that we at least have 100 that we know and we're going to drill 50 in '05, 50 in '06.

Those are those legacy [ones] and when gas prices went from $1 to 6, 7, 8, 9, 10, 11, $12, of course the world reentered the East Texas/North Louisiana and our properties became valuable, very valuable and we started drilling them.

We were not very aggressive on our onshore program. Most of our money was spent in Double A Wells fields. So that's why we announced six months earlier before we would start the drilling program in '05. We're very pleased that we've drilled all those wells. We were disappointed that we didn't head any new reserves. We could've managed that better. That really wasn't our focus in '05; it was to make sure the drilling program would work. It did work and now, as I said, we're broadening our scope and we have got 32 separate fields and we're going to drill in 15 of them because we now have had a year lead way to be able to do that. And Mack has hired a lot of new people.

When Magnum was bought out, quite frankly, Wayne, they gave us some additional good employees here because they are hard to find.

So with that, Mack, I'll turn it over to you as far as the fields and where you're drilling and --

Sure, just to put a point on what -- an additional point on what Jay mentioned is that since I have been here in '97, Comstock has been obviously active in East Texas to varying degrees and the governor on our activity was basically two things. One was the capital required due to our offshore involvements with Bois d'Arc through that venture that limited the CapEx that we could dedicate to onshore projects.

The second was that we were carefully evaluating our ArkLaTex properties and tier ranking them. By that I mean looking at the commodity price versus cost structure versus evaluation of different production profiles that would be required to give us the return on investment that we internally require for project approval. Four years ago, we went through a very careful examination of all of our fields on that basis. And so last year's program was a classic example of preparation meets opportunity. And we executed that program, had great results and it set us up for the '06 program. And then in the middle of '05, we had the opportunity to add to our asset base in the ArkLaTex region through the EnSight acquisition. And fundamentally, that was a great add to our core area in the ArkLaTex region. It gave us an additional set of locations to drill in '06 and to set up reserve adds.

To put another point to it, the program in '06 is a creation out of the '05 program and the EnSight acquisition. And the EnSight acquisition along with our legacy of PUD inventory gives us a go-forward program for the next two to three years at this drilling activity level.

We had -- since 1995, historically, Wayne, remember we've drilled probably 230 wells in this region and we have had probably a 95% success rate. And the average well as you see is about 1.6 million today. So we're in the better part of the region. And that's what we expect our wells will average in '06 in this drilling program, with about a $1.6, $1.7 million cost to drill and complete. And we've layered in these wells equally over four quarters; that gives you the production growth of anywhere from 20, 25% or greater. And we do have the rigs to do that. When we announced the program in September of last year, that 100-well program, we didn't have the seven rigs. And as Mack said, we have them now.

That's great. And that was really my point is that this is an area where you were drilling wells in 2.50 to $3 gas prices because they made sense for you. And today it's nice to have that legacy acreage behind you.

One other question, I think in your EnSight transaction, you also mentioned that you thought you had an asset that was under-evaluated in the Laurel field and it looked like you drilled three wells there last year and I noticed you had 10 scheduled for this year. You didn't really touch on that in your commentary and maybe you could just kind of give us an update on what your thoughts are there on that oil property.

We're extremely excited about Laurel. As you know, we've drilled three wells. All three wells have met expectation. We are currently producing one of those wells to sales at about 160 barrels of oil per day and we're looking at opportunities to improve the artificial lift system to increase that rate. And we have behind pipe pay in two zones up the hole in that well bore. So the other two have been logged and they have more than met expectation. And one of those is currently under completion.

So the activity level in Laurel is quite high for '06. We have the one rig under contract and we're looking for a second rig, as a matter of fact, in order to front-end load some of those projects and get those to sales even quicker.

Ron Mills, Johnson Rice.

Just a few follow-ups on Wayne's. Jay, I think you said the wells in East Texas are costing you 1.6 to $1.7 million to drill and complete. Is that correct? And if so, what are your expected EURs?

That is correct,. The average drill and complete is about 1.65 million. We have an average EUR anticipated at 1 Bcf per well on a statistical average for the 100-well program.

Is that one Bcf per well and those costs, is that all related to Cotton Valley alone or is there any Travis Peak contribution?

No, Cotton Valley alone. Everything else is behind pipe and has not been incrementally added to that reserve estimate.

So, that's also the case in the 1.6 million a day average IP on the wells you drilled last year?

Correct.

I guess to follow up a little bit on one of Larry's questions with the price move, as with all of these resource plays, as the prices have come down, at what price level would you start to pull in your horns? I'm assuming it's well below the $7 price point but what's the economic viability?

We have run different scenarios on that and just as a statistical average, about $5 per Mcf would be the trigger point for us to start looking at decelerating.

Okay. The LOEs in the fourth quarter were obviously higher. Is that expected to be a pretty good run rate on a unit basis given the fact you're now at -- your seven rigs that you will be running in East Texas on the 18 to 24 month contracts, which I am assuming are in that 18 to 20,000 a day range?

Right, well you're talking about the lifting costs, Ron?

Correct.

Yes, because that rig cost wouldn't be in there at all. But basically the rig costs would all be capital costs, not in our lifting numbers. The lifting numbers is really all the field, salaries, electricity and ad valorem taxes and property taxes. And the increase and the lifting cost in the fourth quarter was primarily due to increased assessments by the taxing authorities for ad valorem tax; those were up a lot in the fourth quarter. And of course the severance taxes which are based on sales, they were up a substantial amount too.

The severance taxes will track the sales. So as we come back down into the $7, $8 for gas, that's going to come back down from where it was with the 10.38 gas price.

But we would think that the other lifting costs apart from severance taxes, which we had about 10.2 million in the fourth quarter, that would be -- probably carry forward. So probably $1.50 type lifting cost including severance taxes would be something we would want to use for next year.

Including severance taxes?

Right, that includes severance taxes. And then if prices are much lower of course it will come down a little bit.

Do you have that breakdown between just LOE and --

Sure, in that fourth quarter, 3.9 million of the 14.1 million was severance taxes and 10.2 was all the other cost. Now ad valorem taxes are included in the 10.2.

Okay. I'm going back and forth between you and Mack. In your 2006 program, as you are drilling more -- I guess you're targeting more wells that will result in addition of reserves. And Wayne had mentioned the competition for acreage in the area. Is there any additional acreage in area that would be a perspective for you in terms of looking to add to your position, which would then translate to an even deeper inventory?

The quick answer is of course. And that's all I will say about that. We have identified some areas of interest and to talk any more about it wouldn't be prudent.

Since Wayne asked about Mississippi, San Juan Basin, you drilled sounds like six coalbed methane wells. Can you add any additional information to the San Juan program and what activity level is -- of that 16 other wells, how many are in San Juan basin?

We currently have 10 budgeted for San Juan. Burlington and Cross Timbers are the drivers on that program. And that's the best information we have been given from those two companies. And with regard to other areas of interest, just want to reemphasize Mississippi, as Jay mentioned in earlier comments, we had budgeted $30 million to spend in Laurel and that should indicate the level of importance we've put on that property.

Okay. And then this would be a big picture I guess for you, Jay. East Texas in terms of acreage, what's your current acreage position with your average working and net revenue interest?

Roland, do you have that?

I don't have that exact number, Ron. We should have that soon for the annual report. But I would think we're in the 250 to 300,000 net acres but I will have to give you a more exact number when we factor in all the inside acreage.

I guess I want to make sure that the numbers that Mack had pointed out on cost and reserves and everything are to the [8-8's] in terms of 1.6 to $1.7 million and it will be correct.

Right, those are 8-8's numbers.

Yes. We typically have a 75 -- you can see from the budget, we have about -- a 75% is a rough type working interest in those projects. So of the 96 wells that are in that area we have 74 -- it's 74.2 net wells.

And I'm assuming royalties -- your NRI there is 80 to 85 or roughly --75 to 80% with the remainder being that 20% royalty plus or minus?

A lot of those old leases were eighth royalties.

It's a combination of all kinds of different lease positions but generally that's probably a good rule of thumb.

Van Levy, Dahlman Rose.

Congratulations. It looks like you had a good year. Questions on Mississippi. The wells that you have drilled and on the wells that you are going to drill, is that in the Central Graben of the field where most of the drilling has taken place?

It's a mixture. We have about a third of the projects targeting the central part of the field and if you are familiar with Laurel and the reservoir, it's a stacked, layer-caked reservoir, series of reservoirs. There are 17 reservoirs producing in that field. It is geologically complex. So when you're talking about drilling in the central part of the field, you have to specify which reservoir you're talking about because the reservoirs translate in different directions. We're also targeting a number of projects on the periphery of the field relative to the current production.

I guess that's what I was driving at. Historically, the flanks of the fields, which many people have postulated contain significant reserves, had not been drilled, complex geology, etc. And I'm trying to get a sense of what part of your program could be in this kind of significant reserve adding.

We've got about half of the projects that we feel very confident will give us some additional reserves and with respect to specific reservoirs. And we're also drilling what we call carry the well targets in those specific wells and those are targeted reservoirs that are producing and that have been identified as low-risk targets. And then we have the reserve add reservoirs that our mapping suggests will be there at those locations.

Is that field still being pumped using Rotoflex pumps?

Hydraulic and Rotoflex are the two main artificial lift systems in place. That's right.

Is that your intention going forward? You had mentioned something about trying to get well rates up? Did you contemplate going back to submersibles or --?

We have done that. We're looking at setting larger casing in some wells to accommodate submersibles so we can get the rate up. One of the problems with the hydraulics -- I'll just talk technical just for a couple of minutes -- is having enough injection rate at the surface to power the hydraulic and so we are improving the triplex pump injection capacity of those hydraulic systems so we can get the kind of withdrawal rates that we're shooting for.

What is the production now at Laurel?

Right now we're at about 2300 barrels of oil per day.

And then the typical well, what do you envision cost per well, reserves per well, etc. What is your program based on?

There's a range there depending on the depth and the amount of directional work involved. But between 1.3 and 1.9 million is our drill and complete costs. Completion costs are very well-defined as are the drilling costs due to the history of the drilling or the history of the field. And so we have got a fairly good handle on the cost side element, given that range.

And then reserves per well, roughly?

The reserves per well really range depending on the number of targets and locations anywhere from 200,000 barrels to 0.5 million barrels.

So kind of 6 to 8, 6 to $10 kind of funding costs?

Somewhere in there.

Flipping back to East Texas, can you talk about the risk locations, your inventory, what's booked, what spacing it's booked on, and if there's a potential for down-spacing there?

I will address the question this way that there is potential for down-spacing. [Carp] has just had a field rules changed to 20 acres. We just had a field rules changed to 40 acres in [Warfield]. A number of other operators are pursuing down-spacing field rule applications with the commission. So we found with the '05 program that a number of opportunities do exist with regard to down-spacing. We have not gone to the extent of pudding up our inventory with down-spaced locations at this point in every field that we feel has an opportunity to do s just simply because it's not the time to do that. We are evaluating through the '06 program as we mentioned earlier in the EnSight package of properties.

And what are you booked on now, Mack?

Again, depending on the field, we have a number of different scenarios depending on the field. We're booked in some fields on 160's and others on 80's and there is a couple of fields where it is between 80 and 40's, if you'll pardon that estimate.

Then without the down-spacing, what's the drilling inventory, how many years?

I've got about three years of inventory, 2.5 to three years at 100 to 140 wells per year pace. And that's on one side of the ledger. The other side of the ledger is making sure that we address the infrastructure issues to get the product to market and we're doing that as well right now.

So conceivably if you get half the spacing in the various fields you could move up to maybe a six-year location [unless] you drill out some of the other fields that you mentioned, these four key fields of the 15, you can even extend it longer?

That's our goal.

Another question, you talk about taking drilling times down from 24 to 15, etc. Do you think as you gear up your program more that you could materially continue to knock the cost structure down in this area kind of -- you're still in the steep part of the learning curve? Or have you done about as much as you can do?

We have squeezed a lot of cost out of the average project [AFE] last year and it cost -- of course there has been some cost escalation since then.

And the other thing to keep in mind here is with the Barnett shale play being the exception, East Texas and the ArkLaTex region has the second-highest demand for services in the states right now. The competition for services, of course demand and supply is driving that cost relationship that we're talking about. So we are doing a great job of managing our cost structure and keeping it as low as possible. And if my drilling manager was here, he would tell you there's always room for improvement and he would be right. But we have got most of the cost reductions captured.

Any chance for this casing wild drilling program to be utilized here?

We're looking at that. The problem is we don't like to be the guinea pig company on the front end of something like that. Most ArkLaTex operators are not drilling with casing except where they have a very -- by very I mean 10 to 20 acre spacing rule, where they have got a highly predictable drilling environment. East Texas, although predictable, it's not at the point where drilling with casing is an application in most cases.

But we are looking at the possibility of drilling part of the hole that way but getting a rig set up to accommodate it, getting the crews that are used to that kind of procedure, easier said than done. That's why most operators, us included, are not pursuing that.

And, Roland, could you break out the taxes for the quarter between current and deferred?

Sure. The federal tax provision in the quarter of 24.4 million, 22.5 million is the deferred portion.

And then the exit rate for this year, Roland, in terms of production? [I want to get] the average for the year but what is the sense this thing is going to ramp toward year-end?

You're talking about in 2006?

2006, yes.

2006 we were to kind of -- to meet the upper end of our production target, which is more the 25% growth, we would need to be at about 130 million a day type rate getting toward the end of the year.

As an exit rate. And then my next question was leading into '07, keeping up the same pace, do you think '07 could be another 20 to 25% kind of production increase?

Well, we would have to get comfortable with increasing the number of Cotton Valley wells significantly in order to keep that kind of production growth.

And of '06, what is the -- of the 25% roughly what is the Cotton Valley percentage ramp of that? Is that 15 of the 25 or --?

It's the major driver.

Okay. So if that works, we should be able to program that for several years?

Right. The only other small contributor of course is the Mississippi area. The other areas are just kind of holding their own at best, so the Cotton Valley program is the big production growth area.

Jason Selch, [Magsenter] Capital.

The first question is, it looks like the very high finding costs in 2005 was driven by drilling up all those PUDs. And you mentioned that you have got a 96-well drilling program in East Texas and 156 PUD locations but you've also got 120 Bcf of probable and possible. When you drill up your PUD locations, how much of the 120 Bcf of probable and possible do you expect would automatically then become proved as they are the next location over type of probable and possible out of that 120?

Well, this is Mack. We run the numbers on that and we estimate we can add anywhere between 40 and 60 B's. And that is a risked calculation based on looking at every well that we plan to drill.

Okay. That would be just in East Texas or across the entire Company?

That's just in East Texas.

Okay, so that should generate a pretty good finding cost, I would imagine.

That's our goal.

Now the second thing is it seems like you did a pretty good job of getting the value of Bois d'Arc to be recognized in the market by spinning it off but in Comstock Resources, it's not very well-recognized in the market. And there are other companies out there that have done like a complete spin-off like Forest. What would it take for Comstock to completely spin off Bois d'Arc?

The transaction -- since Bois d'Arc really wasn't our Gulf of Mexico asset, it was a private company and a public company in a joint venture. We have never owned -- we have owned between 40 and up to 60% of the different projects so we ended up owning -- we own 48% of Bogart Bois d'Arc. So given that type ownership, it's not -- there's not a structure that's a tax-free spin-off that is available of our shares of Bois d'Arc. We looked at the transaction as not as a divestiture but simply it was what the product company and the joint venture needed to evolve to that level in order to continue to be successful. It's been a very big investment for Comstock over the years and that was very successful.

As far as not wanting to be and owner of Bois d'Arc, Comstock -- we think it's a great investment and wouldn't see a better place to invest those dollars. And there's not a real efficient way to do a spin-off to keep them completely separate at this point.

So, the transaction accomplished what we wanted to, which was to position Bois d'Arc to have all the tools it needed to continue to be very successful and score in the Gulf. It was never a divestiture like these other transactions are. They're simply trying to divest of their assets.

The one thing we did, as Roland kind of mentioned, we looked at the two men and the team that helped create that wealth and we said we're almost an investor in that program. What is it that we can do to capture that team and have everybody be on the same side? And that program was they would put their wealth in this new company in the form of reserves. We would put our oil and gas assets over the shallow waters in the Gulf of Mexico and then we would take that public. And it would do several things.

First of all, Comstock -- we would not have to fund our 60% ownership in that drilling program, or 40%, whatever that number might be. The second thing was you would have a company that after the IPO I think it had like 10 million of debt because we felt like a Gulf of Mexico company that was not an acquisition borne company should have no hedges in place and it really shouldn't have any debt in place in case you have catastrophic events hit which are back-to-back hurricanes, which the company did have. Because in the market that you're in, it was hard to get a rig. In fact I think 15 rigs were lost because of the tropical storms and the hurricanes. It was really hard to get a rig for the shallow waters and we wanted to have two to three rigs under contract almost in perpetuities because every 90 days we negotiate those three contracts and we would pay market value less the discount.

But the goal for us was to have an investment in that Company, have five of the nine board seats and to create a much better financial company than the way we're structured with just an exploration agreement, which is what we had before the IPO.

In fact, that exploration agreement at the end of this year would have expired anyhow. So we would've had to renegotiate that and you never know if again the craters of that value -- if they want to retire, then you've got a different problem. And now you have those two men owning 23% of its stock. And we had a wonderful conference call from 8.30 to about 9.45 this morning where they went over the 256 Bcfe of prospects, 19 wells that will be drilled in '06, which have been completely risk-adjusted except for the success rate. And historically they have had a 75 to 85% success rate. Last year, a little higher than that. So we think, as Roland said, it's a great investment.

I think the negative part of that you mentioned earlier on and that is the market has not given us any value in that as far as Comstock stock. It's valued Bois d'Arc at a fair value, but that value has not been translated over to Comstock. And I just think we probably had to do a little better job in telling that part of the story, which is less than a year old.

So there's nothing structural you could do to highlight the value of your stock? This has to be up to us to discover it?

What we did, we decided that we want to own 51% and consolidate it in our numbers. And we said no, that's really unfair to the analysts and to everybody else because you will always want that number broken out. So we ended up owning 40%, we used equity accounting. And there's simply a one-line item there that says this is the percent of reserves we would own, this is the percent of debt we would own and this is the value of those shares. And then you have to place that value with our onshore properties.

I think the one thing that we did do is it now is very apparent what that might be worth and if you ever wanted to divest yourself of that position, people can look at it and say well here's what it's worth and there are marketable securities. So we have made it a little simpler in the future if you did want to do something with it.

Paul [Choal] from [Steadfast] Financial.

I have a few questions for you. I was just going through your slides and I just wanted to reconcile your G&A calculation in terms of on an Mcfe basis. I'm just trying to figure out how you get down to your 29 on an adjusted basis?

We don't include the stock-based compensation in that number, kind of looking at a cash margin number.

Right, but if you run this by me again, you reported G&A of 5.5 million in the quarter, right?

Right.

If I take a look at the reconciliation for EBITDAX, I see 1.2 million of stock compensation. So 5.5 plus the, it essentially gets me to 4.3 million and your production was 9.27, right?

Right. Why don't you call us later and we can go through the details.

Also do you have a breakdown yet of your reserves by region?

We have -- let's see if we've got that broken out. Of the total 505 Bcfe, the East Texas region is 259 Bcf of that. Southeast Texas is about 88 Bcf and then I think South Texas is about 49 Bcf. Mississippi is 45; that's mostly oil but that's in [Bcf] there. And then the balance is in of course the other areas, Mid Continent and the other properties. So the East Texas is 51% I guess of the total proved quantities.

Okay. So but theirs went down by about 30 Bcf in Southeast Texas and --

That's the area that we had -- that's one of the large --

One of the write-downs, the other write-down was the other because of that (multiple speakers)

(multiple speakers) those were the two big components.

Right, right, that's fine. Just going back to I think a point that other people have talked about is, you guys paid off almost $40 million of debt in the fourth quarter I think you're down to 29% debt to cap. What is your optimal debt to cap ratio? I mean you're going to be pretty close, I would think to what you would feel is comfortable?

Oh, yes, we think we're probably below that. It is definitely as far as trying to improve that, I think we would want to look at the cash flow, investing that in growth projects or potentially even the stock repurchase to the extent that makes sense. We were able to pay down so much debt last year even in the fourth quarter with the high prices that we have probably got it below where our targets are.

Right, so we wouldn't expect to see anything below 30?

Well I don't think -- I mean I think we should have -- especially on the onshore properties base, you want to have some leverage on it because we can make a much better return. So I think given the nature of the business plan at Comstock, we're probably below the leverage that we should have but we want to have room for future acquisitions so --

One thing too, we did have the two dry holes last year but one of them was a $16 million dry hole. We don't expect that in '06. So we could have paid down our debt another 10 or $15 million without that dry hole or we could've drilled more wells. We didn't expect to get it to 29%. We thought it would be in the low 30's. So I think the 29% is -- I mean we're there. We don't plan on lowering it anymore.

Right, so excess cash flow above your -- your CapEx for now would be allocated to acquisitions or increased drilling or stock buyback?

Correct, that's exactly right.

Now you also referred to this before, I thought you were sensitivity to gas prices in I think it's East Texas, which you said is probably around $5. I assume you plan on funding your CapEx program out of cash flow from operations. What is the sensitivity on that in terms of what level do you get down to around the $200 million? Is that around --?

Like 7.25?

Right, I think that's a mid -- about 7.50 area is where we are really -- where you have the capital expenditures and the cash flow from operations kind of in balance there.

Okay, so it's around -- at 7.50, you're pretty much running even?

Right.

I was just sort of curious because I guess people have -- there have been two acquisitions at public companies in Cotton valley over the past few weeks. Are people -- how is the acquisition market in that area at the moment?

Forest just bought 13 million a day for $255 million or 110 Bcfe and that's announced yesterday. That's the most recent one.

Right. I am just sort of curious in terms of like are people actively talking with themselves or is it more people actively looking in that area? Because I remember speaking to you guys before and you thought the market was a little bit heated. I was just wondering if it's because -- since seller expectations have gotten back down?

I think it's an extremely hot market in East Texas right now because of the predictability of the assets. As to how active different companies are in shopping their East Texas assets, we have a couple in our shop that we're evaluating. But most companies see the same that have East Texas or ArkLaTex assets see it as the same opportunities that we do and that's why it's so competitive for the services, etc,. that I mentioned earlier.

Right, and where are those Forest assets that they just acquired in relation to yours?

I don't know.

I think I just have one other thing here. I just wanted to -- so I think previously you talked about maybe about 15% growth rate in 2006; maybe just my notes were a little bit old. You're targeting 20 to 25% production growth in 2006?

We're measuring if off the onshore production base, obviously, because the offshore is still there but just not reported in those numbers. So we averaged 91 million a day as our onshore production rate in 2005. So we're saying 20 to 25% is in that number.

Okay, is your expected -- okay, good.

That's our targets.

And you'd mentioned the ad valorem taxes, sort of your LOE going up in the fourth quarter. It looks like ex severance taxes, you're probably running at $1.10. I think historically, you've been a little bit lower. Is $1.10 sort of where you're going to be running or --?

Yes, we will be because those new assessed rates are what we have to pay all of next year even though prices go down and then you could argue about them again next year. So unfortunately, I mean with the very high -- given the way they set the property values and the very, very high NYMEX prices that were available to them, we were really hit with very high valuations that we have to pay for next year and then argue next year. Severance taxes at least will follow the commodity prices.

Right, so you [allocate] so okay, but the ad valorem is sort of fixed for the next year at least?

And then we have a lot, obviously, with given that we're in a lot of production in Texas; that's a big revenue source for these areas so they know how to assess it.

That makes sense to me. That's great, I will follow up on the G&A later.

Rehan Rashid, FRB Frank Lloyd.

I'm sorry, all of my questions have been answered. Thank you.

[Sharon Padri], Pilot Advisors.

Thanks, two quick questions. One, I apologize if you already said it. But, just on a full-year basis, could you break out what the exploration DD&A and G&A dollars were for onshore only?

The exploration dollars?

Yes, exploration dollars, DD&A, and G&A? Because that includes, obviously, through May, right?

Right. We will probably have to call you back with some of that real specific like the G&A breakout. I know for just the onshore if you are looking at the total dollars spent for -- out of the 122 million, I think the number was around 28 million or so was exploration related. Of course, the biggest component of that was the Big Sandy. And then we had some South Texas exploration wells.

Twenty-eight for onshore exploration costs, right?

Right. Are you talking about what we charged to the income statement?

I'm just trying to break out on a full -- obviously, the full year includes -- your income statement for the full year includes a portion of Bois d'Arc?

Right.

Unless I'm reading it wrong. Is that right?

No, that's correct.

Through May. I'm just trying to strip that piece out of it.

Yes, so if you look at our exploration expense charge of 19.8 million --

Yes, I just want to take out the Bois d'Arc part of it.

That's about 2.5 million of seismic costs that flowed through in the first part of the year when we were consolidating -- [focused on] consolidating Bois d'Arc. So the balance of that is primarily the Big Sandy well, which is all onshore.

So about 17 million?

Right.

And then DD&A?

I will probably have to give you that number, we'll have to go back and break that out for you. I don't have that in front of me.

Okay, that's fine. And then the second question, I just wanted to clarify your comments about a share buyback. I wasn't sure whether you had an authorization or not. And then to the extent you do and you want to buy back [the stock,] how aggressive are you willing to be at what seems to be a very cheap price?

We do have a $25 million authorized program that was authorized in December. So that's -- to the extent that we fill that, we would go back and look and see if we want to increase that authorization. We would -- we don't plan to significantly changed the leverage situation of the Company in order to do that. We were looking at -- to the extent that we have generated a lot of extra cash flow just in the fourth quarter alone, we had a significant amount of cash flow we generated that we just paid down on our debt. So that we would feel real comfortable investing that into stock with it coming off so much.

With the stock trading for a lot less than what acquisitions costs are out there onshore. I mean the reserves, the embedded reserves in our stock price are much cheaper than the acquisition costs, so we've had the easier place for us to acquire reserves is just by buying the stock back.

So is it fair -- I mean are you in a comfortable enough cash position that today you could not complete the program but definitely do something significant to support the stock here?

Right. Our idea would be -- we don't think we can go in there and try to force the stock to trade where it doesn't want to trade because that's just not a --

I'm just saying are you going to buy the stock back, that's all I'm asking. Like right now, do you have -- want to spend the money today buying back your stock below $26?

Today, we can't because we're in a blackout period. The Company is an insider but under the rules -- there are rules to follow. We're not going to announce our price targets but we do have a plan out there and once we're in an open window again, we will look at it.

Ray Deacon, Harris Nesbitt.

Jay, I had a question about the write-down in terms of the 48 Bcf. In terms of your PV 10 of 1.6 billion at year-end '05, I'm assuming these are kind of long-lived reserves that were written off. What do you think that would have done to the 1.6 billion if they were still included in the reserve base.

I guess there's two comments. Part of that would be putting more valuable reserves on the Double A Wells field that would have a high PV value. And then part of that write-down in Kentucky was very, very low margin on long-lived reserves that had a very, very low PV value. So it's kind of a combination of the two. So maybe it's somewhere in between. But it would definitely be significant.

Okay, all right. So I mean, the PV 10 values [are] proved reserves at about 3 bucks an Mcf. So maybe in line with that or so?

Right, I think you could probably look at that -- that would probably be fair because you have got two extremes. You had one proved, developed, producing property that had those write-downs that was a valuable one and then one very marginal property on the very other end of the spectrum.

Were they wells that were recently drilled in Double A Wells where you had the issue or were they some of your older wells, or was it all the wells?

This is Mack. In Double A, we eliminated two high net revenue PUDs that had substantial reserves attached to them on the periphery of the field and that represented three-fourths of the revision in Double A. We have got a few wells, again, on the periphery of the field that had some load-up issues and we're evaluating an artificial lift system to get those wells back. But in the interim, the revisions were necessary.

And you feel like the issue is pretty much resolved at this point, that probably won't be any further write-downs?

Yes sir, that's correct.

Got it. You did a good job of addressing the inventory but as far as you mentioned the coalbed methane wells. What kind of inventory do you have there in the San Juan? Was that kind of a oneoff thing or --?

The evaluation that we put together about a year ago using the Cross Timbers, the [HDO] pardon me and the Burlington mapping showed an inventory of well over 100 wells. I think it was 115 wells. Both companies have been fairly conservative in their drilling activity there. The last year, they drilled about half the number of wells they had originally planned. But we found this year they appear to be ramping up and it's been a very mild winter there as well in the San Juan. So there are two rigs active right now. So we anticipate, again, through conversations with them, they have confirmed that they plan to drill ten wells this year at a minimum.

Our interest is pretty small, Ray, though, in those projects.

Fifteen percent or so.

Kelly Krenger, Banc of America Securities.

Just a quick question to follow up on the acquisition question that was posed earlier. I think it was kind of limited to East Texas but I was curious in general what you're seeing in the acquisition market and what your view of the balance sheet is in light of any sort of acquisitions that you would consider pursuing?

Kelly, every year, we look at anywhere from 150 to 200 different transactions. We have got an acquisitions team that looks daily somewhere $20 billion worth of different prospects annually. And when we find something in our core area, kind of like EnSight. We looked at EnSight in 2004. We didn't act on it but by March of '05, they had put some hedges in place and service costs went up and we looked at it again, so we bought it in March of '05.

There's always a string of deals like that that we're looking at. We don't budget for acquisitions in our growth model but historically, we probably buy 50 or 100 plus million of assets every year. And I wouldn't be surprised if we didn't do that this year.

I know in the past, I think you have tried to keep the debt to cap kind of in the 30 to 40% kind of contact. Is that generically what we should look at going forward if you were to make an acquisition?

I think our goal, if you remember the EnSight acquisition, we put it under contract and then we did a secondary offering of Comstock stock at $27.50. For $125 million, the EnSight acquisition was $191 million. And hopefully we demonstrated that we're trying to keep our debt to cap really in the low 30s. I mean 34% or less would be a good goal. We're 29% now so we have a lot of kind of wiggle room there.

Evan Templeton, Jefferies & Co.

Hi, thanks most of my questions have been answered but just a couple of housekeeping things. Do you have a exit rate for the fourth quarter?

For production?

For production, please.

I think it was around 104, 105 million a day. We averaged 101 for our average fourth-quarter production rate.

Right. And then also just cash at 12/31?

Cash at 12/31 was only about 89,000 so not very much, you're right.

Great. And also just as far as hedging goes, have there been any changes to I guess the last at least I think public hedging schedule as of 9/30, has that changed at all or are those --?

It's identical. [All forward you know] as positions expire.

What's your kind of current thought? I mean are you comfortable kind of in that 20% range?

I guess we are about 15% hedged on expected production -- gas production. Those are old positions that -- it's a pretty wide range so it's going to be between 4.50 and 9 so, it probably won't have a lot of impact on 2006 unless prices go back up again.

We think we can balance our spending against the current gas price environment. we're really not interested in trying to put in a lot more derivatives. I think that there's a lot of limitations. Like this one, you can see how it's created some pretty bizarre numbers as it's marked to market. I think on the whole, the industry found in the fourth quarter a lot of their hedged positions went ineffective. You'll see a lot of noise there because the gas markets were very unpredictable after the hurricanes. Henry Hub relationships to the different field delivery points has been totally out of whack. We just assume as Henry Hub comes back down that that is going to return to historical relationships. Those are all challenges in trying to run a hedge program.

Right. What sort of -- while you're on the subject, what sort of differential have you seen thus far this year relative to the timing that you have?

Predominantly, we are -- if you look at Comstock, the predominant index that we look at is the Houston Ship channel because it's more indicative of a lot of our production than Henry Hub. And in the past that's been fairly tight to Henry Hub, maybe within $0.25. It got very, very wide after the hurricanes and it hasn't -- it's been as high as a $3 differential. It has now pulled back in at about $1 -- $1.25 to $1.50 but it's very volatile, so it's very hard to predict when it's going to come back to its historical relationship. Different factors are driving it. I think it's been a very weak demand in the Texas markets for gas with the really very mild winter. So that's mostly driving some of the differential that's still there.

Right, just a final question. Just in terms of the revolver you have, is the availability still -- or the size of the revolver about 300 million?

It's now 350 million at the end of the year. That's the total availability, which -- so we have almost 300 million available on it.

David Heikkinen, Hibernia Southcoast.

Lots of questions and I just wanted to give you guys a response opportunity. I remember a report that came out 18 months or so ago about South Texas reserve revisions and now that you had some, was there any link between that report that was written and where the actual revisions came? I just wanted to try to reconcile that on a conference call.

Not to my knowledge. We reviewed that report and that report was on the basis of information that was in the public domain. It ignored pressure data, etc,. and the revisions that we had as I mentioned earlier was primarily related to the loss of two PUDs, high net revenue interest PUD locations that we had significant reserves estimated for. And the report that you are referring to was targeting overall field decline forecasts and didn't address the issue that we had on the periphery of the field. So it's apples and oranges there.

Yes, I just wanted to make sure everything else was asked but just wanted to give you that opportunity. Thanks, guys.

John Malloy, Sound Energy.

Hey guys, how many rigs did it take to drill the 50 wells in East Texas?

Off and on, we had three rigs running throughout the year and we had two other rigs that drilled four wells for us during the year. But three during the year for 90% of the program.

Roland, can you give me or us some DD&A and G&A guidance for '06?

We would look at, when you are going into -- for G&A, we would look at probably a good quarterly number would be about $4.5 million is kind of what we're budgeting for G&A for next year for 18 million for the total.

And then on DD&A with where the fourth-quarter reserves were and kind of where -- but looking at the different regions, probably about $1.70 per Mcfe is probably a good average number for the DD&A rate in 2006.

Does that factor in about 10 to 15% cost inflation for '06? Or is that -- because it looks like in the fourth quarter you did a number similar to that.

I think and the fourth quarter probably is affected a little bit by cost but also maybe by some of the 40 [ABCF] of reserves that were written down. That inflate -- that is reflected in the fourth-quarter rate.

Thank you, sir. We are showing one final question. We have Harry Chernoff, Pathfinder Capital.

You mentioned that you think that the market isn't giving you credit for the Bois d'Arc asset, but if we turn it around and say the market is giving you credit for Bois d'Arc but it's discounting onshore, then that translates your onshore enterprise value to about $1.75 per Mcfe right now, which is not only 25% less than Forest paid yesterday but it's also right around what your F&B costs are for your drilling onshore. So my first question is at some point, do you just say we're going to cut back on F&B because we might as well buy the stock and reduce our CapEx rather than take on more debt or do any other approach?

Well, of course, two weeks ago, the stock was almost 34 and it's at 25 or 26 today and the [beers] have pulled back and we do have, as I've [visited] with you in person -- we do have a stock buyback program. It's $25 million right now and as Roland said, once we spend those dollars and we'll look and see if we need to load again for another $25 million, we probably have the ability to do that. As far as our drilling program, with the $200 million, as we said, at a $7.50 natural gas price, we can fund our CapEx without borrowing any dollars. And one of our goals, Harry, for '05 was to reduce our debt to cap from 53% to actually is as high as 54% down to the low 30s and we ended up getting to 29%. I think we now for the very first time after a couple of days after our blackout period is over after this call, maybe we will be in a position to execute on our buyback program if we want to do that.

My other question, you mentioned your East Texas acreage is about 250 to 300,000 net. But I wasn't clear, how much of that is Cotton Valley?

Approximately two-thirds of it.

Okay. And of the Cotton Valley, you were saying that you had maybe -- help me if I am mismatching your acreage with your drilling program -- about 140 wells per year would take you 2.5, three years and that would be your drilling program in Cotton Valley. Is that right?

That's what we currently have evaluated, yes, sir.

Okay, but if your Cotton Valley acreage is -- let's say your Cotton Valley acreage is 150,000 or something like that.

Come up with a heck of a lot more wells, don't you?

Yes, you do, many, many times. What am I missing?

Well, some of that acreage is currently being evaluated for potential development. And until we get confirmation through the drilling of a well that tests that acreage, we don't put it into a PUD inventory category.

I didn't want to put it into PUD. What I was going to do was say if we're trying to develop an NAV for the whole company, and we say you've got 500 identified wells but you've got 150,000 acres, that's not 500 wells; that's thousands of wells. What is undeveloped acreage in the Cotton Valley in those areas that you're saying you haven't evaluated? What's it going for just as raw acreage?

The raw acreage would be in between fields where there's no drilling, no offset drilling to confirm the producability in the Cotton Valley in those regions.

Oh, no, I understand. But if someone said we would like to buy -- if you wanted to go out and buy or lease new acreage, what would someone pay or what would you be looking at that the market value for what amounts to at least 100,000 acres that aren't represented in your drilling program? Your drilling program is say 80 acres.

Part of that acreage number that Roland gave you includes producing acreage as well. And I don't have the split-out between the producing versus the non-producing. So that is the part of the calculation problem that we're having here in terms of additional drilling inventory, whether it's probable, possible or even unevaluated, to use the other category.

I think we have, Harry, a little over 500 producing wells, like 543 or 550 producing wells. And Roland threw out that 250 to 300,000 acres -- that that includes producing acreage (multiple speakers).

That includes producing. Well a lot of these step-outs are on what -- if it's on 160 acre or 640 acres really, it's classified as producing under because that's what the leases dictate. So even though it could be classified as producing, you could have a lot of locations on that same block. So you can't really -- the math doesn't really work too precisely that way.

I understand that. What I'm getting at is in a very, very top-level view is if you say -- if you said it's 80 acres and you've got 500 wells active at 80 acres average across the whole Cotton Valley, that's 40,000 acres. And let's say you've got another 500 drilling locations, that's another 40,000 acres. That's 80,000 acres and that's 80,000 acres at an 80-acre spacing, you still have another 80,000 acres or so that doesn't appear to be in consideration for either drilling or producing. And the question is, is there some value we can assign to that and say look, this the Company is doing well in terms of X, Y and Z but it has a tremendous amount of unexplored or undeveloped or un-something-ed acreage that isn't being [credited] to anywhere.

That's a good question and in fact someone asked earlier -- they asked Mack -- and I think this was Van Levy asked earlier -- on the drilling inventory if you've got a 2.5 to three-year inventory, if you are successful in down-spacing, could you have a five or six-year inventory. And I think that answers your question. In other words, we don't have nearly all the potential drill sites booked because as Mack said, we don't know if it's goat pasture or drillable acreage. And we won't know until we drill the 100 wells.

It's the other way around. If you down spaced from 80 with the example I gave to 40, which is what a lot of the peers are saying they're going to do, then you have got only 40,000 acres accounted for or maybe 60,000. If you say we have got 40,000 drilled and another 20,000 to account for 500 wells or make it 1000 wells. My point is when I do these very rough calculations, I come up with 50, 80, 100,000 acres that don't seem to be given any value under any conditions. And I'm just wondering what's the value that you would assign to all that acreage?

Well currently, I would assign what the acreage cost is because they haven't evaluated the potential for production in the acreage in question.

Okay, what's that number?

I don't have that number in front of me, the acreage cost. But current leasing in East Texas is going from 200 to 250 an acre.

That's good. That was my question.

Sir, we have no further questions at this time.

All right, Mary, thank you. Thanks for all the participants. It was a good conference call, it was kind of long. For all of you that stayed on for all of it, thank you again.

Thank you. Ladies and gentlemen, this concludes the year-end financial results conference call. You may disconnect and thank you for participating.