Comstock Resources Inc (CRK) 2004 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 this conference is being recorded.

I would now like to turn the call over to Mr. Jay Allison. Mr. Allison, you may begin.

Thank you. Welcome to Comstock Resources' third quarter 2004 financial and operating results conference call.

You can view our slide presentation during during or after the call by going to our Web site at www.comstockresources.com and clicking Presentations. There will you find a presentation entitled, Third Quarter 2004 Results. To change the page in the presentation click 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, who will be available to answer questions. With this call I will review our financial and operating operating results for the third quarter and first nine months of 2004 as well as results to date of our 2004 drilling program. Our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable there can be no assurance that such expectations will prove to be correct.

Page two. 2004 third quarter highlights.

Our third quarter 2004 results include operations of Bois d'Arc Energy which we formed together with our partners at Bois d'Arc in July. Bois d'Arc Energy is consolidated in our third quarter financial statements and accounted for 48% of our sales, 48% of our production, 42% of our pre-tax income and 50% of our capital expenditures in the third quarter. Our solid third quarter financial results, where we reported net income of $12.3 million, ,was impacted by a loss of 540,000 Mcfe, or little more than one half of Bcfe , due to Hurricane Ivan. We also had $9.4 million in dry hold cost due to six dry holes that we drilled in the quarter. We took a charge of $1.6 million in connection with the formation of Bois d'Arc Energy. We continue to have very good results from our 2004 drilling program where 42 out of 52 wells drilled were successful, giving us an 81% success rate. During the third quarter we entered into an agreement to acquire $63 million in producing properties which will add 7 million cubic feet equivalent per day to our production rate beginning in the fourth quarter.

Page three. Oil and gas sales.

For the third quarter of 2004 our oil and gas sales increased to $78.4 million, a 38% increase from sales of $56.9 million for 2003's third quarter. For the first nine months of this year, our sales totaled $205.6 million, 13% higher than our sales in the first nine months of 2003, of $182.6 million.

Page four. EBITDAX.

Earning before interest, taxes, depreciation, amortization and expiration expense, and other non-cash expenses also increased 38% in the third quarter of 2004 to $60.5 million as compared to $43.8 million in the third quarter of 2003. EBITDAX in the first nine months of this year was $159.2 million, an increase in 10%, as compared to an EBITDAX of $144.4 million for the first nine months ended 2003.

Page five. Cash flow.

Operating cash flow. Our cash flow from operations increased 56% in the third quarter this year to $56.6 million, from $36.2 million in the third quarter of 2003. Operating cash flow for the first nine months of this year was $139.5 million, a 15% increase, as compared to cash flow of $121.5 million for the same period in 2003.

Earnings. For the third quarter of 2004 we reported a profit of $12.3 million as compared to 2003's third quarter net income of 12.9 million. The third quarter results include a $1.6 million charge related to the formation of Bois d'Arc. Without the charge we would have made $12.9 million or 36 cents per share. For the first nine-months of this year we had net income of $31 million, as compared to net income of 47 million for the first nine months of 2003 before the change in accounting principles. The first nine months results include a charge of $19.6 million or 12.5 million after tax. Or 35 cents per share relating to the early retirement of our 11 1/4% Senior Notes and the $1.6 million charge related to the formation of Bois d'Arc. Without the loss for the early extinguishment of the bonds and the Bois d'Arc formation cost charge, which were both one time events, we would have made $44.6 million or $1.23 per share for the first nine months of 2004.

Page seven. Average daily production.

Production in the third quarter of 2004 averaged 138 million cubic feet equivalent per day, which is up 11% from 2004 quarter, second quarter, and 2003's third quarter production rate of 124 million cubic feet equivalent per day. Bois d'Arc Energy's production averaged 63 million cubic feet equivalent per day. Our East Texas/North Louisiana region averaged 26 million cubic feet equivalent per day. Our Southeast Texas reached average 31 million cubic feet equivalent per day. And our South Texas and other regions averaged 18 million cubic feet equivalent per day during the third quarter. Without Hurricane Ivan, Bois d'Arc's production would have averaged over 70 million cubic feet equivalent per day.

Page eight. Average oil prices.

Our average oil price increased 44% in the third quarter of 2004 to $42.46 per barrel as compared to $29.50 per barrel in the third quarter of 2003. For the first nine months of 2004, our average realized oil price increased 26% to $38.67 per barrel as compared to $30.79 per barrel for the same period in 2003.

Page nine. Average gas price.

Our average gas price increased 16% in the third quarter of 2004 to $5.85 per MCF as compared to $5.04 per MCF in the third quarter of 2003. For the first nine months ended 2004, our average realized gas price of $5.76 was 2% higher than last year's average price of $5.65.

Page ten. Cost per Mcfe.

Third quarter cost per unit of production. Our lifting cost per Mcfe produced increased 17 cents in the third quarter of 2004 to $1.21 as compared to $1.04 in the third quarter of 2003. The increase is primarily attributable to the lost production during September due to Hurricane Ivan. Our G&A per Mcfe, excluding stock based compensation, increased 7 cents in the third quarter of 2004 to 20 cents as compared to 13 cents per Mcfe in 2003's third quarter. The increase was attributable to higher G&A associated with Bois d'Arc Energy.

Our depreciation, depletion, and amortization per Mcfe produced increased 26 cents in the third quarter 2004 to $1.57 per Mcfe as compared to $1.31 per Mcfe in 2003's third quarter. The increase is attributable to additional interest in the Bois d'Arc Energy properties which have an average rate of $2.01 per Mcfe.

Page 11. Costs per Mcfe.

Nine-month costs per unit of production. Our lifting cost per Mcfe produced increased 15 cents in the first nine months of 2004 to $1.17 as compared to $1.02 in the first nine months of 2003. Our G&A per Mcfe excluding stock based compensation increased 3 cents in the nine months of 2004 to 18 cents as compared to 15 cents per Mcfe in 2003's first nine months. Our depreciation, depletion, and amortization per Mcfe produced increased 12 cents to $1.46 in the first nine months of 2004 as compared to $1.34 per Mcfe in 2003's first nine months.

Page 12. Cash margin per Mcfe.

Our cash margin on a per unit based improved by 24% in the third quarter of 2004 to $4.75 as compared to 2003's third quarter cash margin of $3.84. For the first nine months into 2004, our cash margin was $4.58, a 5% increase as compared to cash margin of $4.37 for the first nine months of 2003. The increase in margin is attributable to the higher oil and natural gas prices.

Page 13. Capital expenditures.

We spent $111 million on our drilling program in the first nine months of 2004 as compared to $60.6 million in the first nine months of 2003. In the first nine months of 2004 we drilled 52 wells, or 25.2 net to our interest. 42 of the 52 wells drilled this year were successful and 10 were dry holes. We spent $49.5 million to drill 34 development wells of which 33 wells were successful. We spent an additional $19.8 million for work-overs and recompletions, off-shore production facilities, and other development costs. We spent 40.2 million on our exploration program. 36.5 million was spent to drill 18 exploratory wells of which 9 were successful. $3.7 million was spent to acquire exploratory acreage. We also spent $700,000 on an off-shore acquisition in the first quarter.

Page 14. East Texas/North Louisiana region.

We drilled 9 successful wells, or 6.8 net wells, in this region so far this year. We have tested 5 of the wells at a per well average rate of two million cubic feet equivalent per day, the remaining 4 are being completed. We plan to spend $20 million in this region this year and will drill 7 more wells in this region before the end of the year. For 2005, we expect to spend $45 million in this region to drill 50 wells. We expect production from this region to increase by 10 million cubic feet equivalent per day next year with a new drilling program which will be a primary driver of our on-shore production growth along with the Ovation acquisition.

Page 15. South Texas exploration program.

We have drilled 22 wells, 6.8 net wells, in our South Texas region, in the first nine months of 2004. 16 of these wells were successful and six were dry holes including a deep test well drilled in Missouri county, Texas. 14 of the successful South Texas wells were tested at an average per well rate of 4.3 million cubic feet equivalent per day, the remaining two are being completed. We are currently drilling two wells in South Texas and expect to drill two additional wells by the end of the year including an offset well to our discovery in the Javelina field in Hidalgo county. Our discovery well in this field is expected to be producing at an initial rate of 7 million cubic feet equivalent per day in the next several weeks. We have a 66% working interest in this well.

Page 16. Southeast Texas region.

In our southeast Texas region, we are currently drilling the Collins #3 well to the south of our Ross prospect area. This well should reach total depth of 15,500 feet sometime this week. After evaluating a new 75 square mile 3-D seismic survey, we have identified several high impact exploratory prospects. We plan to test our Big Sandy prospect with an 18,000-foot exploratory well to be drilled south of our Ross prospect area. After evaluating the results of the Big Sandy prospect, we will drill the Robin prospect in 2005.

Page 17. Gulf of Mexico region.

In the first two quarters of this year, we drilled 13 off-shore wells, six net wells, in our Gulf of Mexico region. These wells were drilled under our exploration program with Bois d'Arc off-shore or as part of our redevelopment of Ship Shoal 113 unit. All but one of the offshore wells were successful. In July of 2004 we contributed our offshore Gulf of Mexico properties to Bois d'Arc Energy in exchange for 59.9% ownership of the new venture.

Since its formation Bois d'Arc energy has drilled six off-shore wells. Three were successful. Three were dry, that we reported on last week. The successful wells include the OCSG 63 #3 well drilled as Ship Shoal block 93 to test the Goldfish prospect. The well was drilled to a depth of 12,420 feet and encountered 58 feet of productive pay in three zones. Bois d'Arc Energy has an 80% working interest in this well. The second successful well was the SL 10830 #6 well drilled at Ship Shoal block 66. This field extensional test well was drilled to a depth of 10,830 feet and found 27 net feet of productive pay in three sands. Bois d'Arc energy has a 100% working interest in this well. The third successful well was drilled at Vermilion block 127. The OCSG 22621 #1 well was drilled to a depth of 7,020 feet and found 148 feet of net productive pay in eight commercial sands. Bois d'Arc Energy is currently drilling three off-shore wells, and we expect Bois d'Arc Energy to drill an additional three wells by the end of this year.

Page 18. The Ovation acquisition.

In October, we closed an acquisition of producing oil and gas properties in the East Texas, Arkoma, Anadarko, and San Juan basins from Ovation Energy LP for $62 million. The properties being acquired have proved reserves of approximately 42.3 billion cubic feet of gas equivalent and were acquired at a cost of $1.47 per thousand cubic feet of natural gas equivalent, or $1.88 per Mcfe including future development costs related to the proved reserves. The proved reserves are 99% natural gas, and 66% are in the proved-developed category. We acquired 165 active wells and will operate 69 of the wells. The operated properties represent approximately 69% of the value of the acquisition. The acquisition will add around 7 million cubic feet equivalent per day to our daily production starting in the fourth quarter.

Page 19. Our capital structure.

At the end of the third quarter our debt increased to $381 million, up 57 million from our total debt of 324 million at the end of the second quarter. 60.6 million of our debt is attributable to the minority interest owners of Bois d'Arc Energy. Without the minority interest debt, and the $6.6 million deposit we made in the third quarter for the Ovation acquisition, our debt would have decreased by $10 million in the quarter. Our stockholders' equity was $332 million at the end of the quarter giving us a 53% debt to total cap ratio. Without the minority interest debt this ratio would be at 49%. After the closing of the Ovation acquisition and the planned refinancing of the Bois d'Arc Energy debt, our debt to equity will fall to 46% on a pro forma basis.

Page 20. Outlook for the rest of the year.

We expect our capital expenditures to total $225 million this year, including the $63,000,000 Ovation acquisition and 56 million of expenditures of Bois d'Arc Energy. Next year our drilling budget will approximate $200 million, with 112 million related to Bois d'Arc Energy and the balance to be spent on our on-shore properties. Production should be up considerably in the fourth quarter as we recover from the effects of Hurricane Ivan and add the production from the Ovation acquisition. We are expecting production to average between 145 to 155 million cubic feet equivalent per day in the last quarter. When Bois d'Arc completes its refinancing of our $151 million loan, which we now believe will not occur until the first quarter of next year, our debt will fall to 46% of our total capitalization, even after the funding of the $63 million acquisition of the Ovation properties.

With that let me turn it over for questions, please. Hello?

Yes, thank you, sir. We will now begin the question and answer session. (OPERATOR INSTRUCTIONS) Our first question is from Ron Mills from Johnson Rice. Please go ahead.

Good morning. On -- Jay, if you can walk through a little bit more detail on East Texas and the property or at least the project there. I think these are the properties you acquired from So-nad(ph) and you really hadn't been spending any money on them. Can you walk through your inventory and what the typical well is expected to cost, reserves, just so we can get a sense as to the economics of that play?

As you know, Ron, in 1991 we really started acquiring interest in drilling wells in that area and then in '95 you had mentioned So-nad. We paid about $50 million for a little over 300 wells and some big acreage positions there. And we did not aggressively develop that, mainly -- If you look at nine years ago commodity prices, particularly gas, was a lot lower than it is today. We looked at our acreage position and we said we've got about 12,000 undeveloped acres. They've been drilling these wells on 40-acre spacings, so there are about three hundred locations. And we said, "Well, how many of those are good and how many are not good?" And we traditionally, we came up initially with -- we said we have at least 100 solid drill sites and we may have more than that. But right now we've reported that we have at least 100 drill sites. And we put a program together, as you know, which says over the next two years we plan on drilling 50 wells per year. Fifty in 2005 and 50 in 2006, and the economics as we see the wells today, they are vertical wells.

This Hosston, Travis Peak, Cotton Valley, Cotton Valley lime-type production. Most of these wells are Cotton Valley, they are 10,000, 10,500 feet in depth. They are about $1.1 million to drill and complete. And you are going to see reserves of anywhere from 1.1 to maybe 1.4 Bcfe of reserves. So your finding costs are a little less than $1. As you know since 1995 we drilled 146 wells in this area. We've had a 92% success rate. What's happened to us is that not through any acquisitions that we've made recently but because of the things we did nine and ten years ago we have created a great inventory of prospects to drill in East Texas/North Louisiana. And as commodity prices increased, the value of that acreage increased because the reserve values increased. And, in fact, the COO made good, that was kind of his area of expertise, the East Texas area, and if he wants to add something to that, Mack.

Briefly, just to let everyone know what our status is, as far as being able to ramp-up that program. We have two rigs running in the Arka-Tex region now. We have a third rig schedule to move in next month and we are slowly ramping the program to allow us time to build location, get well locations permitted so that we can ramp the program in the first quarter of '05. So in the last four to six-months, Comstock operations and land personnel have been building the drill-ready inventory. It's one thing to have this on page much it's another thing to have everything handled in the proper way, regulatory and otherwise. So we are prepared at the end of this year and starting early in the first quarter of '05 to ramp the program.

We reported almost 90 days ago that we would have this 100-well program, and based upon that we've aggressively received a lot of drilling permits. We've built locations. We have bought tubulars so that we wouldn't have any problems with that program and in fact, Ron, only two areas of our production have we put any hedges in. One is East Texas and the other one is the Ovation acquisition. Because we do final drilling at least in the 100-well program in '05 and '06 and we did that to protect the program.

And on these, on the wells especially in the Cotton Valley, what kind of initial production rates are you expecting from these wells? Would it be similar to the 2 million a day that you're total program in the area has? Or are these more like 1 million to 1.5 million IPs?

We are anticipating IPs between 1.5 to 2 million a day. The other thing that we are addressing as part of our program is the drill time and the complete time. Historically, we've taken about 60 days to drill, complete connect to sales the wells we've drilled and over the last three to four months with the two rigs that we have and in the Arka-Tex region now, we've been progressively lowering that drill time and completion time. So we are excited about the opportunity to be -- not only be able to ramp the program but be able to put these wells on sales a lot quicker than we have in the past.

The other thing, Ron, you may ask, why do we have such an inventory and the answer to that is in -- If you look at 2001, commodity prices were high in the first quarter, they dropped dramatically in the second quarter. Third quarter and fourth quarter of '01 we borrowed $161 million to buy 164 Bcfe of reserves which was the DevX acquisition. Then you get into 2002 commodity prices were low. 2003 in January our goal was to really solve our single largest corporate problem which was our $220 million of bonds that had 11 1/4% rate on them. So we took what we thought our free cash flow from operations would be and we earmarked about 90 million of that for CapEx but we earmarked about 60 million to pay down our debt. Because we needed to the get our debt from about 64% debt to cap to 50 or 51% debt to cap. So we would have a chance in 2004 to tender for the bonds which, they were eight-year notes non-callable for five years. So the first time we could call them would be early 2004. In fact we did that and as we reported earlier, that was the $19.8 million one-time event for early extinguishment of debt. But because we had this different corporate goals we didn't have the dollars to put in East Texas. So now the positive part of that is that we ended up with a huge acreage position with a lot of prospects. We've been there a long time so we should know what we are predicting to do out there. Since it's a big plus for the company.

Okay. And you provided the fourth quarter production guidance of 145 to 155 million a day. Now that you've brought, it sounds like you brought substantially all the production on, back on line from the hurricane and tropical storm impacts, where is your current production and what are the fourth quarter production adds that -- to get you up to that number? I'm assuming Ovation is a big part of that.

Remember, October, the month of October we had about 10 million a day shut in because the Tennessee gathering line was down. And that's in the Gulf of Mexico.

On-shore we've got currently a net production of approximately 80 million cubic feet equivalent per day and the additional adds that we are expecting in the fourth quarter obviously we anticipate Collins #3 in South Texas. We have a well in Javelina that is currently flowing at approximately 4 million a day and we will ramp that production to plus 7 million a day, as Jay indicated earlier. We have additional wells that are completed completing in the Arka-Tex region. Right now, in addition to those that are drilling, we will be completing in the fourth quarter. So those will be additional production as well in the fourth quarter.

And, Ron, remember we own I think 66% of the Javelina will. That's a Shelf farm-out, so that's a new event for us and as we said we will probably drill an offset well to that. And then we do have some production off-shore, four big wells that we predicted would come on December 1 which will add pretty significant production. That's at Vermilion, South Marshall Islands.

In terms of the 2005, have you all -- are you all ready to hazard a guess in terms of a range of what have kind of production growth we can expect, especially now that you are consolidating Bois d'Arc and Ovation is behind you?

We aren't quite ready to get too definitive on guidance in 2005. Although, I think what we see is that we will have a very strong production rate by the end of December, both from on-shore and off-shore. And then on-shore, we see that we can maintain that rate and add to it with the East Texas program. If we rely mainly on the East Texas program, and we think it's going to be predictable kind of production, and we see that adding 10 million per day to that region. I mean that would be, that would give us the kind of growth on-shore to get us a 15% plus growth. And off-shore we are -- will be less predictable there but we are pretty confident too. We are going to end up with a pretty good end of the year production rate as we get to the rest of the discoveries on line. A lot of these -- some of these go back to being drilled, even back into last year. And then as we start drilling new wells. So I think our goal is to achieve a 15%-type production rate. And that will be after taking into effect the additional production that we are picking up from the way we are consolidating Bois d'Arc. It will be on top of that. Since we've got, we will have Bois d'Arc in really two quarters of this year and it will be four quarters potentially next year there will be a change there.

If you look at our estimates right now, Ron, it is -- we are looking at a 15% or so growth rate, period.

But the 15% doesn't account for six months of consolidating Bois d'Arc.

We will have that in addition. So we would have a higher number if you are just looking at gross numbers on the top.

That's correct.

Then finally, then I'll turn it over, on the cost side, are the third quarter costs pretty representative of what have you expect going forward now that some of the higher costs, Bois d'Arc properties, are in there from an LOE standpoint and DD&A standpoint?

I think the DD&A rate is probably -- until you can factor in new discoveries and stuff, it's probably pretty indicative. The LOE is high because most of our lifting costs are fixed and with the shut in production it is -- that rate is a much higher rate than it would be back with everything on-line.

Would you expect to it trend back to kind of that 105 to 110.

Yes we would. We would expect that, that that would be kind of where the right -- should trend back to the fourth quarter and then hopefully improve our on-shore LOE rate should improve next year because a lot of this new production from East Texas using our existing operating personnel and infrastructure and won't add a tremendous amount of incremental LOE that Mack -- Where we haven't always had their increasing lifting cost rates because again lifting costs are relatively fixed and production has been declining there. Now we will reverse that trend.

On the G&A side once you have all the Bois d'Arc, what's a good quarterly run rate on G&A?

On G&A I think the third quarter is probably pretty indicative of total consolidated G&A. It was $3.7 million. We probably will use, maybe, a higher number next year just to use -- We're using about 4.2 million a quarter just to count for potential increases and costs. I think that should be pretty indicative. Because that reflects the full operations of that company in the quarter. And most -- really the only change -- the change from our previous quarter to this quarter was just all related to including their G&A in the consolidated numbers.

Okay. Thank you much.

Thank you.

Our next question comes from Ray Deacon from Harris Nesbitt.

Hey, Jay, I was wondering if you could tell me whether there is any further drilling to do at South Pelto #25? And where are the last three wells that Bois d'Arc is going to drill located, for this year I guess?

Well, there is some -- we are actually evaluating South Pelto #25 pretty extensively right now and there is an excellent chance that we will drill another well there. Obviously the last well was a disappointment and that's why the geologists are going back and scratching their heads on that. That is -- there is a well that may be drilled or need to be drilled by the end of the year under our farm-out of that lease and they are still evaluating were whether or not we are going to drill that well or use that rig for another project. That's kind of up in the air and I think it's more than 50/50 chance we probably will drill a well there.

Got it. And the three additional wells will you drill by year end, those are -- where are those?

Those are all in the Ship Shoal, mainly the Ship Shoal and South Timbalier area, just three additional prospect. We have three wells drilling right now. One of them is almost finished with a prospect over at South Timbalier #38 and it might even finish up by the end of the week. And then they'll start another well, as well as the other two rigs. So basically they are all on a well now and will probably have to drill one more well out of the prospect inventory.

Remember, Ron, we have two rigs under contract run now, we are using the third one also. We've got a longer term contracts for the two rigs.

Right. Okay. Can you just remind me what's had the left to be hooked up that has been drilled?

We have four wells at Vermilion, South Marsh Island, which should be hooked up. Initially we said by the 1st of November because of hurricane everything got pushed back a month so we said December 1.

Got it.

Those are 4 big wells when you add them all up. There are some other thing like some of new wells to be hooked up but that's the big impact as far as hook-ups up there.

Okay. Great. Just lastly the Collins #3, is that a PUD location or would that add new reserves?

We think it has a potential to at new reserves.

Thanks.

Next question, Richard Friary from Delphi Management. Please go ahead.

Looking at the Ovation acquisition and some of what you've been talking about in terms of finding and development costs. I'm wondering if you can keep them in the range they are at or if potential acquisition are looking a little more expensive right now?

When we looked at Ovation, typically we stay in a market that we are in today which is almost an all time high oil and gas price mark. You shouldn't really be drilling through acquisitions. That's our rule of thumb. What we did with Ovation, we looked in each of those four areas. We either have existing production or we've had production. If you look at the geo-physical team that evaluated it, they understood operations in those areas and they thought there was a lot of upside. And so we said, what percent of the production is in East Texas? And then we looked at the Texas Panhandle which is where we started the company. And the Panhandle-type production in Arkoma, we even sold $10 million of production in the last six or seven years to another public company.

We understand all those basins, and the technical team wanted to go forward and we looked at the cost and said, well, it really adds to our East Texas program right now. We know it's $1.46, $1.47 for the cost and then another -- if you look at the add -- the remaining reserves, it's about $1.88. But I think our overall attitude was that when we plotted the decline covers we were very careful and when we looked at the 69 or 70% of the value that we would operate we were comfortable. With looked at San Juan and we said, well, that's an XTO-Burlington-type of area. They are the operators but they will be an aggressive operator so we looked at that and we were comfortable with that. And we said, we really understand it and I think the key to that is as I mentioned to Ron Mills earlier, the two areas that we have put costless collars in, where we hedged , where we think you have to if you have something about the commodity price markets they are in. We put a four- fifty floor and we put anywhere from an eight-twenty to a 10 dollar ceiling for the next two years for Ovation. Then we plugged it into our numbers and we said it is accretive to cash flow and earnings and we said it is. Then we even go back and we try to say, is it a material acquisition to the company? I mean did it increase our size by 50% or double it, and the answer is no. It incrementally didn't do that much. Then we said if it were a much larger acquisition and maybe some of the bigger companies would have looked at it and in fact would have bid it up higher because the seller was representing about 15 or 20 Bcfe greater reserves than what we reported and yet it was large enough that you had to have real money to buy it. It kind of fell in that spot where we thought we should go ahead and do it. 100% of the engineers and geologists, including Mack, approved it and wanted to do it and we thought it was the right thing to do. It is a little costlier than what we've been doing, but hopefully the reasons that I just gave you are the reasons we did it.

If you go back to 2001, December of '01, that was our last acquisition, that was DevX. And before that it was the Bois d'Arc assets that we bought in December of '97. So we went four years really without any acquisitions from '97, to '01. Starting in January of '02 we didn't buy really anything in '02, '03, and it was in October of '04 that we had another acquisition and during the time frame between '02 and '03 and the first six months of '04, we looked at about $15 billion of possible purchases, about 350 different transactions, and this is the one that we bought. So we do look a lot. We don't by very often.

Right. You mentioned in East Texas the finding cost and some of the incremental acreage there of under a buck?

Correct.

Is that something you can continued to do on some of your other properties or is that an anomaly?

I think in East Texas you have to look at how we acquired that acreage position.

Right.

What is some companies have done they have gone in in the last year or two and they are aggressively bought their way into East Texas which means that in this market, as I said earlier, you have to pay for proved-undeveloped locations. I mean there's a value in this market for those. But if you go back to 1991 and 1995, we had two big acquisitions, each in '91 and in '95 in each of those years. We didn't, we would buy gas in the ground at maybe 20 cents, 30 cents per Mcfe And all the really, the locations that you see today they had no value back then because the value appeared because the commodity prices have gone from $1 to 4,5,6, $7. And when those, when the commodity prices increased, well, the reserve values increased. In fact, the proration units were down-sized where you would normally drill on, say, 180s you would go to, you would go to 80s and then you will go to 50s. Since the 40-acre spacing, that's really created the value here and the high commodity prices, as far as can we do that in the future? I said earlier we do have about -- if you just look on how many locations do we have, it's about 300. But then if you get real, well, we say how many of those locations are what we call goat pasture, how many of those would you never drill? And we don't really know the number to that, but we do know we have 100-plus locations for '05 and '06 and hopefully in the future if you go beyond that we have another 100 or so. We never expected in 1991 or '95 to have 300 locations in 2005. And that value just kind of appeared. So.

Right. A couple of quick, other questions. You talked about the production growth, someone asked a question about that earlier but what's the real production growth from the drill bit? Because I know you've got some acquisitions, you consolidated Bois d'Arc, I'm wondering a good figure for drill bit production is?

Ron, you have --

Well, the acquisition basically is 7 million a day-type add to the production level, maybe that grows to 8 to 9 million per day with some wells we want two drill on the acquired properties. It's mostly --

The rest of that would be.

Driven by the drill bit. And we are having to replace of course the declines which are always out there in all the different basins.

I think you will see the immediate growth in off-shore in Vermilion and South Marsh Island wells, which were drilled a year ago, but those should be some high impact wells. And then hopefully, like Mack had mentioned, we've got the wells which is a farm-out from Shell, which is at Javelina, which is a 7-plus million a day well that we own 66% of. And then the Collins #3, hopefully that would be a good well. We probably own 56% or so of that well.

And then from there we are going to use the same unit rig and are going to move it over and we'll drill the if first Big Sandy well. The Collins #3 well and first Big Sandy well will be the first two wells that we've drilled off the new seismic that we finished and that was in August that we announced that. And I think the prospect at Big Sandy that will take, that's an 18,000-foot well, that will take 70 days, Mack? That will take 70 days before we reach total depth on that well. And then based upon the evaluation there, we will drill what we call the Robin prospects. In fact on the Robin, there was concern of can you get per permits in a big ticket and we've had some meetings on that and said we are trying to get two permits right now but the what if scenario, what if we never get permits? We think on the east and west side of the ticket we have have the locations and we have drill underneath the thicket. We would probably be using five -- if it were fully maximized, in other words the value was there as we see it, that's probably nine rig locations that we would have on the east and the west side of the thicket and we were drilling until drilled underneath the thicket. It probably cost us 5 to $7 million more to do that than having a location in the thicket. But I think the good part of that is that whether we ever get a permit in a thicket or not, we can develop the Big Sandy and the Robin areas.

One other thing you talked about your capital structure earlier but as you generate free cash going forward, is your number one priority to pay down debt? To put it back in the drilling program? To buy in stock? Do you have a list of priorities?

Our priority, we'll spend around the $200 million for CapEx next year. And then the free cash flow over and above that we are going to use that to pay down our debt because our goal would be to get our debt to cap at 40% or less. We would like to be in the 30s. But you have to see where commodity prices land on that one.

Are you buying any stock right now or do you have any authorization?

No, we don't have a current stock buy back plan in place. Our number one priority is to continue to improve the balance sheet and we wouldn't buy back stock unless there was an extreme situation with the debt to cap, the amount at our goal, which it's not at our goal.

We would like to get at debt to cap at 40% and then look at stock repurchases.

Thank you.

Your next question comes from Kelly Krenger with Banc of America.

Good morning, just a couple follow ups. Jay, did you say you wanted to get debt to cap to 40% before you would look at share repurchases?

That's kind of a rule of thumb. We as a board have not decided on that, but a material part of our budget is exploration and I think that it would be wise to get it to 40%. That's always a good goal, and if we could get it to 38% it would even be better.

The 45 is exactly where would we would like it to be for sure. Anything above that we are going to continue to have debt reduction as a priority. As you get to that number and below it does probably lessen as a priority but still, it would still be an important priority until you get probably below 40.

We said, Kelly, maybe by the end of the first quarter or so we should be 46, 47, something like that.

Okay. And then on -- I can't remember what slide it was, you showed what pro forma debt would be post the Bois d'Arc transaction and also post the Ovation acquisition, was that, I think that number was like 113 million, was that just 150 million down of debt reduction from the Bois d'Arc transaction and then add back the 60 to 65 or whatever it was for the Ovation acquisition?

Right, except for Ovation you would, basically we see 150 million coming in from the Bois d'Arc refinancing. The Ovation acquisition was 63 but six was already incurred in the third quarter as we paid a deposit. So you just take really 90% or -- 90% of the purchase price of Ovation is what's in that pro forma because six is already outstanding, it was debt in the third quarter.

And is the push back on Bois d'Arc to the first quarter, is that primarily just --

Just the time it's taken to get any kind of comments from the SEC. We think realistically given that you are approaching. Thanksgiving holidays and then it's going to be difficult to get that process closed out with them until we get into next year.

We will be reviewed by the SEC if you just look at the time frame. It might be possible for a December event but we don't think it's practical. We would rather everybody look at it as a first quarter event to be safe.

One clarifying question on your production for next year you said 15% production growth in '05. I'm a little confused on what base that is from. I guess if you have fourth quarter production of 100, and call it midpoint of 150 million cubic feet per day, presumably that will have Ovation in it, it will have one month of the off-shore production that you expect. So would that be -- with the 15% growth would that be based on the fourth quarter production? Is that the right --

We are looking at over 2004's production not our exit rate. Our exit rate will be pretty high compared to the production rate for all of '03. We are looking at from year to year.

We will compare '04 to all of '05.

'04 to all of '05? You said -- okay, so that's whatever your stated '04 production will be up 15% in '05 is what, what you are anticipating?

I think the key to that, Kelly, is that we are going to start off at a much higher rate because we should have a great exit in the fourth quarter of '04.

Okay. So reported '04 to reported '05 should be up 15%?

And basically what we are saying is if you factor out the minority interest component of the production we would have it up 15%.

Right.

Because that itself creates probably a pretty big number. For part of the year, it's in two quarters of this year. It's not in the first two quarters -- So if you pro forma it into the first two quarters and then looked into it that's how we would be looking at our growth target.

Okay.

So I would say maybe on a pro forma basis maybe it's a good way to talk about it. We would have production up from '04 to '05.

Okay.

Which would show those pro forma numbers in our 10-Q and 10-K, so as if Bois d'Arc Energy would have been formed on January 1. You will be able to see those.

Okay. Thank you very much.

Thank you, Kelly.

Thank you. Our next question comes from Rehan Rashid from Friedman Billings.

Morning, Jay. Going back to Big Sandy, could you just give any update in terms of designs behind that? Any more work that's making them look better, worse? And also is Collins #3 and Big Sandy, are they going to be independent of each other? And the same thing applies for Robin and Big Sandy.

I will let Mack start this off and then I will add to it.

Briefly for me, yes, there's been considerable amount of work on the new 3-D data set that has adjusted the bottom-hole location of Big Sandy. Just to geographically orient everyone, Big Sandy is about 2 miles south of the Collins #3, bottom-hole location. And, yes, the Collins #3 is independent of the Big Sandy. We believe they are in separate geologic features. The science behind it, we think we've identified the depositional axis of sand transport. And we feel very comfortable with that interpretation, the new 3-D has allowed us to further refine that and adjust the bottom-hole location of Big Sandy. We are set up to spud that well within the next, probably, 3.5 to four weeks.

And that well, Rehan, Big Sandy will be drilled by the unit crew that's drilled the Collins #3. We kind of broke Big Sandy a way from the Robin. They are stand-alones as far as reserves. And the Big Sandy, if you look at the slides, we are saying it's over 100 Bcfe reserve target. You have the whole Big Sandy area is probably 300 Bcfe It will take probably half a dozen wells to prove that up. But this will be the first well -- This is based upon the new 3-D seismic which Mack and the technical group has spent weeks and weeks and weeks reviewing. And the big question there is, did it confirm what we thought we might be drilling? And the answer is it did. And it could have been that it wouldn't but it did and that's the meetings that we've had with Mack and that's why they've been excited about these prospects. We delayed, if you remember, the drilling of the Collins #3 until we got the new seismic back because we overlapped the old seismic which is the Double A area and the Ross area with the new seismic area which is the extension of the Ross area plus Big Sandy plus Robin. And then we wanted to see what the Anadarko well looked like, the old Arko(ph) well looked like and tie that in together. So that's why -- Instead of dropping south and drilling a well first, what the geological group wanted to do is they wanted to keep marching down from the north and kind of march to the southern part of our lease play and I thought that was wise that they wanted to do that.

Once again the Collins #3 is also the drill site location as subsequent to looking at the new 3-D seismic data as confirming --

That's correct, Rehan.

Lastly again on Robin you had mentioned earlier that it's going to be -- you are going to evaluate Big Sandy first and then drill Robin. Does that mean they both are tied or separate geologic features?

Obviously if Big Sandy meets expectations we are even more confident about but.

That's the easy part.

Exactly. But everything factors into our decisions and the data that we acquire from Big Sandy will certainly be relevant to Robin. But they are independent events.

And, Rehan, on Big Sandy we will test the upper and lower wood line. It will take us another 20 or so 30 days maybe to deepen that well to the lower woodbine. Because if we do hit the lower woodbine, there will be some pretty meaningful reserves there. And it will be about a $3 million dry hole. What is it, if it's a dry hole?

4.2.

4.4. It's about a $2.8 million or so with the upper woodbine, but if you deepen it up to the lower woodbine, it it's about 4.2, $4.3 million dry hole cost.

At one point there was talk about bringing in some partner, do you feel comfortable going 100% here.

We've elected right now, Rehan, to drill it on our own.

Also on your CapEx budget for next year, 200 million, could you break it down for me, 45 million in the South and East Texas, plus Louisiana, right? What's the other breakdown?

Well, 112 is Bois d'Arc Energy and then the balance is split between South Texas and southeast Texas. We have not definitively got this budget all -- but that is going to depend on how some of these projects come out. But most of those dollars, exploratory dollars in those two regions, will be competing for the balance.

Right, we will shuffle those dollars, Rehan, back and forth from South Texas to the Big Sandy, Robin, Ross area.

One last question. The Bois d'Arc drilling the next year, 112 million, in terms what have we are pursuing, is that going to change any, meaning the mix between the normal regular shelf to deep shelf, anything there?

We plan on that program being as predictable in the future as it has been in the past and the business plan is not to change it up any.

It would be a combination of the deep shelf wells like they drilled. Plus the shallower stuff probably in the same kind of proportions. ,To the extent that there's really some extensive deep projects they will probably bring in partners, and to the extent that there's not then we might not have partners. And that's kind of how we this year's first quarter we are in.

On South Pelto 21, 22, again at one point there was discussion that maybe drilled some more wells within that block. Any update on that?

22 and 25?

Yeah.

Right. They are doing a lot of seismic analysis work on 22. And we've agreed with the other partners there that that work would be -- get some production history and do additional seismic work but there are some other targets to drill. Then that would be, probably, something that we would look at next year. And 25, we would have to make a decision on the drilling there and they are looking at that. We have a rig that can drill the next well there. Obviously the last well, while it did encounter sand, it wasn't commercial enough to be warrant completing. They are trying to decide on that well where we want to go with that. And I think there's a good chance we will drill one more well there, but there's a possibility that they will also decide that the risks are too high. We won't know that answer probably for another month or so.

Okay. Thank you.

Thank you. Our next question comes from David Heikkinen from Hibernia. Please go ahead.

Take (indiscernible) questions, unless you can talk a little bit about exit rates per area, do you have any feel for your production off-shore? What you can expect in Texas, southeast Texas as far as exit rates?

As far as the offshore component, I think the exit rate on-shore is probably going to be pretty -- it would be just a little off from where Mack says it is today with some -- especially at the Collins, we don't know about the Collins #3 yet so it would be a big factor. Because that's a big well. But, yeah, I think even if it is similar to where it is today we are pretty much on track so that's just the bonus if it is going to be much higher. But the difference in the current production today and where it will be at the end of the year will be mostly off-shore and we are getting back to kind of the rate where we were before Ivan. And then as we get to the final other projects on, we will be -- we will have an exit rate up there that's maybe a little higher than our on-shore rate in between, and closer to 85 million a day there.

All right.

That's as long as they turn on those wells we will do that. We are a solid 70, probably 75 million a day, kind of, without all those wells coming on and they would add to that. And then we have the potential to hit, maybe, up to 90 million a day there, but that's probably if everything works perfect in the best case scenario. So that's why I say maybe in the mid-80s for off-shore is a better bet to predict on.

And then, just wanted to get the exact production split per each one of the areas for the Ovation acquisition. Do you have the seven, is it divided basically equivalent to the reserves or a little more in East Texas? Just making sure I'm adding things in right.

I think, yeah -- of course, all of it we have to show in our other region, other than the part that's in East Texas. And I think that is about 1.5 million, is that right, Mack? About 1.5 million per day, 2 million per day is the most that comes from the East Texas --

And the rest is just --

The rest is all in our -- will be in our other South Texas, we kind of combine that because -- into one reporting area. Although most of that's really other, not South Texas.

All right. That's all I needed. Thank a lot, guys.

Thank you. Our next question comes from Ron Mills from Johnson Rice. Please go ahead.

Just doing some final housekeeping. Roland, can you walk the current hedges that do you in place in terms of volumes?

Sure. It's about 15 million a day is what's that -- we have a costless collar with the four fifty-floor that's the real protection and the cost of it was us giving up the 10-dollar ceiling for '05.

Will that breakdown.

That's for '05 and '06.

And will that be broken down in your 10-Q?

Yes, we will include a table on what the positions exactly look like. But they all start, they all start for January, '05, and go through the end of '06. And our goal is to add to the '06 position and we are working on that and looking for opportunities to improve our ceiling or something. We would like to raise the ceiling in '06 to a higher number and we would also like to add more volumes from these Texas program heads. We are working those two kind of goals together and see if we can't accomplish raising that eight-twenty five ceiling up. So we don't have to pay under it.

Right. And then maybe it's just for Mack but on the Gulf of Mexico wells that are awaiting completion, especially at South Marsh Islands and Vermilion. What expected volumes are waiting completion on the Gulf?

Production rates anywhere from 20 million to 30 million per day. That's an eight-eights number.

I think we may own 75, my guess is we own 75%.

75% of the, of the upper numbers, 30 million. We've given.

75 percent, that's, take the royalty out, too, Ron, when it comes to net numbers.

And the royalties is a typical 12.5% royalty? or 20? Where is it?

I would use 20 just for your rough numbers.

Okay. And then on the balance sheet, what, on the other liabilities, what's the components for the minority interest, Roland?

What's the minority interest? Well, of course, all we had in this quarter was just their contribution of their actual historic cost into Bois d'Arc and then they had their share of earnings. It's basically $50 million, it's $49.7 million of historical cost in assets they contributed and that's how they were record. And then 3.2 million was their share in the third quarter income that we reflect as of deduction from the income statement.

So roughly 53 million is related in the minority interest line?

3.2 million, right. So that bring their liability up to 52.9 million at the end of the quarter.

Okay. Thank you.

Thanks, Ron. Thank you.

Our next question comes from Pavel Molchanov from Raymond James.

Good morning. Just a question in regard to your free cash flow. Obviously most of it will be again dedicated to debt reduction. But is there any chance of a cash dividend sometime soon?

No.

Not a very good one. I think that our first goal with the excess cash flow which we will have some in the fourth quarter and then into -- if prices hold up, pretty substantial '05, will be to reduce the acquisition debt we incurred with Ovation. As we reduce that debt we will be making other acquisitions I'm sure so unless the acquisition market is just totally unreachable, we would look to grow the company before, if the opportunities are good. Before starting to have a dividends strategy.

Ron, we always say you shouldn't by the stock for a cash dividend because the likelihood of that happening is not very great.

Understood, thanks.

The next question comes in from Ray Deacon from Harris Nesbitt. Please go ahead.

Hey, Roland, could you tell me what the deferred taxes were in the quarter?

Oh, sure. The deferred taxes were, just in the quarter, we had a total tax provision was $6.9 million, 5.9 of that roughly or, 854,000 was deferred and 1,075,000 is current.

Okay. Got it. So.

Hopefully, as the company -- With the entire commodity prices, our taxes are becoming more and more complex as we are now using up a lot of our NOLs and starting to really have to show current taxes. As long as our drilling program is very aggressive and active we ought to still be able defer a large percentage of our current, of our booked tax provision. Next year, just for estimation purposes assume that we can defer 75% of our taxes, and let -- unless commodity prices come down then have current tax liability at closer to 25%.

Got it. What kind of budget does that assume? Being able to defer 75%?

Just the kind of budget we have in place now. Basically a $200,000,000-type budget.

And against the only way to really accurately determine this minority interest deduction is to build an income statement for Bois d'Arc. You gave the DD&A rate but how does the LOE expense without --

We actually if you -- that's in the press release.

Oh, okay.

That schedule there.

Okay.

So you will see that. I mean they are actually on the lee right(ph) with $1.25 in the third quarter but it was mainly distorted by Hurricane Ivan pretty substantially. I think they go back to more of $1.10 on a normal basis.

I see what you're talking about.

You will see that we did break out the operational numbers in the press release between Comstock and Bois d'Arc to help you tie back into how these would be presented in the future.

And you're probably, you are not going to have a year end reserve report before you go out and try to do the offering, I guess.

I don't know.

Okay.

I don't know the answer to that. We typically strive to have our year end reserve estimates out by mid-January. Worse case towards the end of January. That's usually the first thing we release into -- as far as closing out the activity for '04 will be for reserve evaluation.

Okay. Got it. When you talked about 100 locations on the East Texas properties I guess a question for Mack, what are you assuming on spacing there? Is that all 80s and some 40s? Is that right?

Yeah, it's a mixture. Depending on the field, the area that we've talking about. If you use 100-acre, pardon me, 100 well locations the spacing will be between 40 and 80 acres. As a range.

Okay. That's been pretty consistent with what other companies around you have been doing.

Right. We did a thorough evaluation of all offset operators in each of those areas and 40 to 80 acres is pretty common.

Great. And any issues with getting rigs or have you already log locked those up?

We have three rigs locked up. Two currently operating, for us and one mentioned coming in early to mid-December and we have a fourth that we are first in line for so if you haven't in the East Texas region if you haven't already made your arrangements you are too late.

Got it. All right. Thanks, Mac.

Yes, sir.

Our next question comes from Eric Kalamaras from Wachovia Securities.

Roland, can I verify the ceiling on the hedges? I thought you indicated $10 another point I thought you mentioned something about eight-twenty five.

There's two different ones. There's a ten-thirty is actually the ceiling for '05 and it's eight-twenty five for '06.

That's what I needed. Thank you.

Our next question comes from David Heikkinen of Hibernia.

Just a follow up, and of looking at valuation, on an enterprise value for Mcfe you guys trade at a discount. Even if you -- I know you want to first use cash to pay down debt but could you be buying back stock before the Bois d'Arc IPO, are you allowed to or is that even something that is possible?

We are allowed to. I mean, we have certainly the latitude under our debt instruments to buy back stock based on as long as we are buying it back out of earnings which we have a tremendous amount of build up in our restricted payment-type limitation. It's not at all outside imposed limitation.

The internal goal.

We think it's important to have a stronger balance sheet and as acquisitions opportunities come up we want to have that flexibility.

Okay.

We just don't think it would be a prudent idea. We can't really respond to the day to day stock prices and try to step in there.

Just was want to go clarify.

We have in the past, when it's been an extreme situations like after 9/11, step in. Of course we had really had -- we were at our kind of target debt to cap then, too, but we also needed an extreme situation where the market was just way in a different world and we did by a lot of stock back out then.

We have the ability to do that right now, David, if we wanted to.

Thanks, guys.

At this time we should know further questions.

All right. Well, I would like to thank everyone for listening in. I know you've got a busy schedule and again we think we should end up with maybe the best year in the history of the company. And I believe that we've set 2005 and 2006 to be the better years. So thank you.

Thank you. Ladies and gentlemen, this concludes the third quarter financial results conference call. You may all disconnect and thank you for participating.