Comstock Resources Inc (CRK) 2004 Q2 法說會逐字稿

Good morning ladies and gentlemen and welcome to the Comstock Resources Second Quarter Financial Results Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question and answer session. Please note that this conference is being recorded. I would now like to turn the call over to Mr. Jay Allison. Mr. Allison, you may begin.

Thank you Christine. Welcome to Comstock Resources second quarter 2004 financial and operating results conference call. You can view our slide presentation during and after this call by going to our website at www.comstockresources.com and clicking `Presentations`. There you will find a presentation entitled `Second Quarter 2004 Results`. To change the page, in the presentation click the arrow on the page. I am Jay Allison, President of Comstock. With me this morning is Roland Burns, our Chief Financial Officer and Mack Good, our new appointed Chief Operating Officer, who will be available to answer questions this morning. With this call, we will review our financial and operating results for the second quarter and first half of 2004 as well as the results to-date of our 2004 drilling program. I will also discuss our recent announcement concerning our new joint venture with Bois d' Arc in the Gulf of Mexico. Our discussions today will include forward-looking statements within the meanings of the Securities Laws. What we believe the expectations in such statements to be reasonable. There could be no assurance that such expectations will prove to be correct.

Page #2: The 2004 Second Quarter Highlights: Our sales and net income for the quarter ended 06/30/04 was the second highest of any quarter in the Company's history. Our revenues reached $66.5m. We generated operating cash flow of $45.4m and way around $18.7m or $0.52 per share in this quarter. Our drilling program continues to deliver good results, 28 out of 32 wells we have drilled this year have been successful, giving us an 85% success rate. We will spend some time on this call discussing our joint venture in the Gulf of Mexico. We believe that the new venture can be a catalyst for growth for Comstock, both in the Gulf of Mexico as well as onshore. The planned refinancing of the venture debt will substantially improve our balance sheet. Page #3: Oil and Gas Sales: For the second quarter 2004, our oil and gas sales increased to $66.5m as compared to $57.2m in 2003 second quarter. For the first half of this year, our sales totaled $127.3m, 1% higher than our sales in the first half of 2003, a $125.7m.

Page #4: EBITDAX: Earnings before interest, taxes, depreciation, amortization and exploration expense and other non-cash expenses increased 17% in the second quarter of 2004 to $52.5m as compared to $44.8m in the second quarter of 2003. EBITDAX in the first half of this year was $98.7m, down 2% as compared to $100.6m in 2004. Page #5: Cashflow: Operating Cashflow: Our cash flow from operations increased 21% in the second quarter of this year to $45.4m from $37.4m in the second quarter of 2003. Operating cash flow for the first half of this year was $82.9m, 3% less in cash flow of $85.3m for the same period in 2003. Page #6: Earnings: For the second quarter of 2004, we reported a profit of $18.7m, which represents a 34% increase over 2003's second quarter net income of $14m. For the first half of this year, we had net income of $18.7m as compared to net income of $34.8m for the first half of 2003. The first half results include a charge of $19.6m or $12.6m after tax or $0.33 per share relating to the early retirement of our 11.25% notes. But that's a loss on the early extinguishment of the bonds; we would have made $31.2m or $0.88 per share. Page #7: Average daily production: Production in the second quarter of 2004 averaged 124m cubic feet equivalent per day, which is up 6% from 2004's first quarter and 2003's fourth quarter production rate of 118m cubic feet equivalent per day. We averaged 45m cubic feet equivalent per day in our Gulf of Mexico region, 27m cubic feet equivalent per day in our East Texas, North of Louisiana region, 33m cubic feet equivalent per day in our Southeast Texas region, and 19m cubic feet equivalent per day in our South Texas and other regions during the second quarter. The Gulf of Mexico region accounted for all of our production growth this quarter.

Page #8: Average oil price: Our average oil price increased 30% in the second quarter 2004 to $37.55 per barrel, as compared to $28.83 per barrel in the second quarter of 2003. For the first six months of 2004, our average realized oil price increased 15% to $36.24 per barrel, as compared to $31.39 per barrel for the same period in 2003. Page #9: Average gas price: Our average gas price increased 6% in the second quarter of 2004 to $5.77 per Mcf as compared to $5.44 per Mcf in the second quarter of 2003. For the first six months ended 2004, our average realized gas price of $5.71was 5% less than last year's average price of $5.98. Page #10: Cost per Mcfe: Second quarter cost per unit of production. Our lifting cost per Mcfe produced increase $0.12 in the second quarter of 2004 to $1.10 as compared to $0.98 in the second quarter of 2003. The increase is attributable to higher fixed operating cost in our Ship Shoal 113 unit in which we required higher interest in late 2003. Our G&A per Mcfe excluding stock base compensation decreased $0.03 in the second quarter of 2004 to $0.15 as compared to $0.18 per Mcfe in 2003's second quarter. Our depreciation, depletion, and amortization per Mcfe produced stayed the same at $1.35 per Mcfe in both periods.

Page #11: Cost per Mcfe: Six months cost per unit of production. Our lifting cost per Mcfe produced increased $0.13 in the first six months of 2004 to $1.14 as compared to $1.01 in the first six months of 2003, the increase is again solely attributable to additional operating cost in our Ship Shoal 113 unit. Our G&A per Mcfe, excluding stock-based compensation decreased $0.02 in the first six months of 2004 to $0.15 as compared to $0.17 per Mcfe in 2003's first half. Our depreciation, depletion, and amortization per Mcfe produced increased $0.05 to $1.40 in the first half of 2004, as compared to $1.35 per Mcfe in 2003's first half. Page #12: Cash margin per Mcfe: Our cash margin on a per-unit basis improved by 12% in the second quarter of 2004 to $4.63, as compared to 2003 second quarter cash margin of $4.15. For the first six months ended 2004, our cash margin was $4.48, a 3% decrease as compared to cash margin of $4.64 for the first half of 2003. The decrease is mainly attributable to lower natural gas prices.

Page #13: Capital expenditures: We have spent $72.1m on our drilling program in the first half of 2004, as compared to $39.2m in the first half of 2003. In the first half of 2004 we drilled 33 wells, our 13.6 net to our interest. 28 of the 33 wells drilled this year were successful and five were dry holes. We've spent $33m to drill 22 development wells, of which 21 wells were successful. We spent an additional $12.1m for workovers and recompletions, offshore production facilities, and other development cost. We've spent $27m on our exploration program. $22.7m were spent to drill 11 exploratory wells, out of which seven were successful. $4.4m were spent to acquire exploratory acreage. We announced today that we are increasing our capital expenditure budget for development and exploration activity this year from $110m to $150m. Approximately $80m will be for development activity and $70m will be for exploration activity. The increase is driven by our new Gulf venture and an increase in activity planned for our onshore properties.

14: East Texas, North Louisiana region. Production averaged 28.4m cubic feet equivalent per day in this region in the first half of 2004, down about 10% from 2003's first half production rate, a 31.5m cubic feet equivalent per day. We drilled four wells, or 2.3 net wells in this region so far this year. All of these wells were successful development wells, and we have tested two of the wells at an average well rate of 2.5m cubic feet equivalent per day; the remaining two wells are being completed. We are increasing our drilling budget in this region to $20m, an additional $12m from the previous budget of $8m. In the second half of 2004, we've planned to drill 13 development wells in this region. The additional 11 wells being drilled this year are part of the first phase of a 100 well infield development program being launched by us to exploit our properties in this region. This program will extend to 2005, and 2006, and be a significant part of next year's budget. We believe that this program will reverse the production decline that we have experienced in our largest region over the last couple of years and contribute to our production growth in 2005.

South East Texas region, page #16. Our production averaged 32m cubic feet equivalent per day in the first half of 2004 in our South East Texas region, which was up approximately 1% from 2003's first half production rate of 31.6m cubic feet equivalent per day. Our fifth successful Woodbine well in our Double A Ross area to Davis-Blackstone #1 well was drilled in the first quarter and put on production in the second quarter, had an initial production rate of 8.2m cubic feet equivalent per day. We have a 48% working interest in this well. Planned development and exploratory activities in this region is waiting on the receipt and evaluation of 75 square miles of new seismic data that we expect to receive in the next couple of weeks. We plan to drill five more wells in this region, including two wells to test the northern parts of our Robin prospect. All of these wells are contingent on the result of our evaluation of the new seismic data.

Page #16 South Texas/other regions: Our production averaged 19.8m cubic feet equivalent per day in the first half of 2004 in our South Texas and other regions, which was up approximately 41% from production in this region in 2003's first half of 14m cubic feet equivalent per day. We drilled 14 wells, 4.8 net wells in this region in the first half of 2004. 10 of these wells were successful and four were dry holes. Seven of these successful wells were tested at an average per well rate of 4.5m cubic feet equivalent per day. The remaining three wells are being completed. Five of our successful wells are development wells drilled at out J C Martin field in the Zapata County, where we have a 16% working interest with a high revenue interest of 25%. We have also drilled three development wells at our Bar range field in Kenedy County, where we have a 20% working interest. Two of these wells were successful and one was a dry hole. We also drilled a Lopez #2, a successful development well in Starr County, the remaining five wells drilled were exploratory wells; three of this exploratory wells were dry holes and two resulted in discoveries. The Gonzales #1 was drilled to a depth of 11,400 feet in Zapata County and discovered approximately 25 feet of net pay in the Wilcox formation; we have a 45% working interest in this well. We made a discovery in Hidalgo County, where our first Javelina prospect well drilled to a total depth of 13,856 feet, and found approximately 44 feet of net pay in the Vicksburg formation and there is another 215 feet of potential pay that we are still evaluating. We obtained an interest in the Javelina field through a 1,282-acre farmhouse from Shell; we have a 66% working interest in this well and we have a 50% working interest in future wells drilled of this acreage. One successful development well was also drilled in one of our fields in Oklahoma in which we have a 21% working interest. This well has been tested at a rate 8.2 Mmcfe per day. We have increased our budget in this region from $15m to $20m because of additional exploration opportunities that we now have. We planned to drill 11 additional wells in the last half of this year including a high potential prospect in Brazoria County.

Page #17: Gulf of Mexico region: Our production averaged 40.8 Mmcfe per day in the first half of 2004 and our Gulf of Mexico region, which was down 4% from production in the first half of 2003, a 42.3 Mmcfe per day. We have drilled 13 offshore wells or six net wells in the Gulf of Mexico in the first half of 2004. All but one of the offshore wells were successful. The one dry hole was drilled in the first quarter. Six of this successful wells drilled with Bois d'Arc were reported with our first quarter results including two successful wells at Vermilion Block 122, a successful sidetrack of a well at South Timbalier Block 11, the third well at South Pelto Block 22, the second well at South Pelto Block 25, and the third well at Vermilion Block 51. In the second quarter, we've drilled a development well at South Pelto Block 5, this well was drilled to a total depth of 16,334 feet and found 97 feet of net productive pay. We had a 25% working interest in this well. We also had two new exploratory discoveries in the second quarter. The OCS-G 22702 #1well at Ship Shoal Block 135 was drilled to a depth of 7,991 feet and found 26 feet of net productive pay, and the OCS-G 22702 #2 well Ship Shoal Block 134 was drilled to a depth of 13,006 feet and found 53 feet of net productive pay. We have a 40% interest in these wells. These wells are waiting on the installation of production facilities, which is expected to occur in December. We drilled and completed three wells in our Ship Shoal 113 unit during the first half of 2004, the three wells have been tested at a per well rate of 2.5 Mmcfe per day. Three of our offshore projects had productions start-ups in the second quarter - at South Pelto 22, two other wells are flowing approximately 1,275 barrels of oil and 3 Mmcf of natural gas per day with the third well awaiting recompletion to 31 feet pay sand.

The initial discoveries at South Pelto Block 25 well is flowing approximately 1,570 barrels of oil and 1 Mmcf of natural gas and the second well is awaiting a recompletion of a 17 feet pay sand, Vermilion Block 122, which includes three wells also started up production operations. These three wells are currently flowing approximately 13.3m cubic feet equivalent per day. Two wells at Ship Shoal Block 109 and 110 are expected to be online September 1. We have four wells of Vermilion Block 51 at South Marshall and 220 that are expected to come online in November, and the two wells drilled at Ship Shoal block 134 and 135 are expected to come online in December. We've increased our exploration and development budget for this region to $90m from $67m. The increase is driven by the contribution of our Gulf of Mexico assess to Bois d'Arc Energy. Due to our 59.9% ownership in Bois d'Arc Energy, we will have a higher interest in offshore exploratory projects in the new joint venture company compared to the 40% participation in the previous exploration venture with Bois d'Arc. In the second half of 2004, we've planned to participate in drilling 13 offshore wells; there are ownership in Bois d'Arc Energy. Capitalization: Page #18: At the end of the second quarter our debt decreased to $324m down $15m from our total debt of $339m at the end of the first quarter. Most importantly, all of our 11.25% bonds retired, which save us approximately $11m annually. We had $149m outstanding under our new bank facility, which has a borrowing base of $300m. Our stockholder's equity was $316m at the end of the quarter giving us a 51% debt-to-total capitalization ratio, improving two points since the end of the first quarter.

Page #19: Our new offshore venture: On July 16, we contributed substantially all of our Gulf of Mexico properties and $103m in debt to Bois d'Arc Energy, LLC, a newly formed company. Bois d'Arc Resources and its two principles Wayne Laufer and Gary Blackie together with certain other partners also contributed their interests in the Gulf of Mexico properties to the new company. Comstock received a 59.9% equity interest in Bois d'Arc Energy for this contribution. The ownership interest was based on the relative value of the reserves contributed. Our Service Chairman of the Board Roland Burns will be the CFO of the new company. Wayne Laufer and Gary Blackie will run the company on a day-to-day basis with oversight from Comstock. Until the end of the year, Comstock is providing a revolving line of credit up to a maximum amount of $200m of which approximately $152m was drawn at formation. Comstock will fund the credit line with our bank credit facility. We expect to refinance the amounts owed to Comstock by December and are currently contemplating an initial public offering of the common stock of the new company depending upon market conditions. Comstock plans to retain a 51% ownership in Bois d' Arc after the refinancing. This combination will be unwound if the refinancing is not successful. We plan to account for our interest in the joint venture company using proportional consolidation meaning that we will reflect our 59.9% interest in Bois d' Arc in our financial statements. If Bois d' Arc completes a public offering of its stock, we will have to fully consolidate Bois d' Arc in our financial statements and reflect a minority interest liability for the share of its operations that we do not own.

Page #20: Benefits of the new venture: We're extremely excited about the potential for the new venture that we have entered into with Bois d' Arc. Our previous venture with Bois d' Arc, which started in 1998, has been a large part of our exploration success over the last six years. We believe that the new company with its focused and very experienced offshore management team will be even more successful in creating value and challenging, but very rewarding Gulf of Mexico. We'll have a higher stake in future Gulf of Mexico exploration prospects generated by Bois d'Arc, 59.9% versus our 40.0%. If we continue to have a similar success rate that we have had over the last six years we should have higher production and reserve growth from the Gulf of Mexico in future years. But the termination of the old exploration venture, we will no longer issue warrants for successful prospects. We issued $7.5m of warrants under the old exploration venture last year. We will be responsible for our share of the new Company's G&A expenses. The combined offshore operations team that the new Company will have, will allow for more efficient and effective management as a combined offshore properties of the contributors. Another benefit as a new structure is that our capital intensive Gulf of Mexico exploration program will be self-funding, which will allow us to invest more in our onshore properties, including our East Texas, North Louisiana region, which have under invested in. This year it would equate to a faster growth rate for our onshore properties as well as our offshore properties. And lastly the higher Gulf of Mexico growth, and the onshore growth can be achieved with a stronger balance sheet. Bois d'Arc's repayment of our loan will substantially reduce our outstanding debt, and our debt to total capitalization should drop to 40%.

Our 2004 outlook. Outlook for the rest of the year. We are increasing our capital expenditure budget this year to $150m. This increase provides for more drilling in East Texas and North Louisiana, as we kickoff 100-well drilling program on our acreage in this region. Much of this program will spill over into 2005, and into 2006. We have also added to our South Texas exploration budget and additional prospects to be developed. Our expected production increases had been slower to develop than we anticipated, as the increases based on the timing of the startup of production at certain of our Gulf of Mexico properties. We are now expecting our production to be 7% to 8% higher than 2003. We are now seeing the benefit of our February 25 debt refinancing with $11m in annual savings that it generated. With continued strong natural gas prices, we should generate cash flows in excess of our capital expenditures either with the increased budget, which will allow us to continue to reduce our debt. When Bois d'Arc completes it's refinancing of our loan, our debt will fall to only 40% of our total capitalization, achieving our goal for materially less leveraged balance sheet. With that , let me open it up for questions.

Thank you. We will now begin the question and answer session. If you have a question, you will need to press star then one on your touchtone phone. You will hear an acknowledgement that you have been placed in queue. If your question has been answered and you wish to be removed from the queue, please press the pound sign. Your questions will queued in the order that they are received. If you are using a speakerphone, please pickup the handset before pressing the numbers. Once again, for any questions, please press star then one on your touchtone phone. The first question comes from David Heikkinen from Hibernia. Please go ahead.

Good morning. Just wanted you to go through first year offshore production in South Pelto 22 you had two wells that are producing about 10Mmcf to 11Mmcf a day. The recompletion, what type of rates would you expect to see from 31feet a pay?

David this Mack Good. We anticipate rates approaching 5m equivalent per day, at a minimum based on the net pay a we are going to.

And still more liquids biased on that zone or is there gas here?

I believe it's gas.

Okay. On same type of question on South Pelto 25, put the recompletion there to 17 feet a pay. What do you expect from that?

Basically the same rate.

Okay, kind of the minimum of the 5m or at the same rate as the first 12 or --?

It's 5m to date, David.

Okay. And then looking forward -- looking at the third quarter, Ship Shoal one will have impact, did you have test rates on those wells or no?

I'm sure we did not.

Okay, and kind of the same type of 10m a day combined from the two wells, that are prior expectations?

That's where we are modeling in, David.

Okay.

In our product growth David, plus what we've done -- we said for the 5m for each of those wells and we've given the upper zones in 22 and 25 we've given that type of daily rate, and hopefully, they will be better than that. I mean, again we have been disappointed in the production rate of 22 and the second well at 25, I think in spite of that you can say we've had a 6% growth in our production rate in second quarter. And really in spite of that we think we can have the 7% or 8% growth for the year. But hopefully. It's just kind of -- when you start at the bottom zone and you perpetrate from the bottom up, you don't cut corners. Sometimes you want to and you want to skip a couple of those sands, but it's not the right thing to do. We are trying to be patient in completing those upper sands. I think Mack, what we have 11 sands in that first well at 22.

And we have 11 net pay sands in the two wells and health of 22.

So, to get part of that David is that we do have a lot of sands behind part, the bad part's that we haven't really seen any material production from them because we hadn't them.

With the rates that you are getting, you are kind of thinking about half the rates, maybe of what you are expecting to two-thirds of the rates? Are you having any reserve impacts to either your end reserves or what your expectations are from the fields in the Gulf of Mexico?

Well, what's happened also is they've been -- we thought initially there was mainly natural gas. And what's happened is it's been mainly oil. So, you either get your production rate, its making lot more oil than we thought, and Like that South Pelto 25, the number five well, 1500, almost 1600 barrels of oil per day. And that's -- we did not expect that to happen. We thought that would be a 15m a day gas well or so. So, really the question is, what size is the reservoir, because if the reservoir is as big as we think it is, it's oil that'll be positive. If it's smaller, of course then you have a negative impact. We are still evaluating that.

Okay, but, I mean if you had the same size acreage coverage, you'd actually have potentially positive revisions or higher reserves, just to lower productive rate and a low longer reservoir, is that a fair way to think about it? Is that what you said?

That's what I think Jay is saying. Is it not? I think it's -- by the end of the year we'll have a good deal for the reserves, but we were thinking just generally on those properties that them reserves are going to be pretty similar, but with a longer production horizon, they are not gas, and not going to flow them as hard. So, a lot of the reserves are really into behind pipe category more than in the -- this well and that's producing.

We really and internally, we said is probably a neutral event, and that oil is more valuable right now than natural gas. But, we are producing it at a lower rate than we thought.

Got you. On your East Texas acceleration and the plans going into '05, give a feel for initial rates on the wells, 2.5m a day, kind of drilling 50 wells a year in '05 and '06, is what your thinking on the in-field program?

With the exception of the rate, we modeled 1.5m a day initial rates from the wells we'll be drilling, and the goal is to -- you are exactly right, drill complete and connect 50 wells in each of '05 and '06.

And remember what we did is, we had acquired that acreage back in really '95 from , a lot of that was acquired back then. And we drilled, it's at 2001, 2002, 2003, we drilled 18 or 19 wells a year there, and then when we really focused last year on paying down our debt, so that we could tender for the bonds, we cut back our program in East Texas. When the gas price doubled or tripled, then Mack's people looked and said well we've got about 12,000 undeveloped acres there, on 40 acre spacing we've got a lot of locations, how many real locations do we have and what kind of problems that we had getting rigs to drill the wells. And so we've said, we safely have about a 100 locations and the program is, is that by the first quarter of next year hopefully we have six active rigs drilling wells in East Texas, our neighborhoods that we have already acquired nine years ago. And these types of problems in the wells historically, I think 1995, at the end of last year, we drilled about a 146 wells in that area. We had about a 92% success rates, so with the acceptant that we have done historically, what is going to do more of it the latter part of this year in '05 and '06.

The average recoveries there, and completely well costs on your East Texas properties?

Sure, the average drilling complete cost currently is about $1.2m per well gross, and average of our reserves depends on the area, we have nine different areas in the outer Texas region, we are going to be drilling, and reserve range will be between $1b and $1.5b per well.

Okay, and what's your average net interest?

Average net interest, again David, it depends on the area, but you roll everything together, it's -- you are looking at an average working interest of about 65%.

Okay. Just one additional question on the Robin Prospect. The two wells in the second half are those later in the year, or have a little time for interpreting the 3Ds, or kind of thing late third quarter or fourth quarter timeframe?

Right, we are looking at tempting despite the first, that was Robin well in October, second with the end of this December timeframe. And David the hardest part of the sheet is been done and that's the actual sheet itself, so, I mean, that's why we put the big question mark, and that has been done. So now, like we said in the call earlier, we think that in the next week or so, two weeks we should perceive to the data, and from there -- I mean, we did say that we are finally drilling two wells. That's not in the middle of the Robin area to the south, this is to the North, but we will drill directional wells underneath, the big dig, it is our plan.

And any update as far as being able to permit our drill in the big dig. Is that still in progress or is that everything going to be directional underneath?

Nothing really to report there, they are working the problem.

Okay, I appreciate it. Thanks guys.

David, one other thing. In South Texas, we didn't touch on this, but we will be drilling a well with not petroleum, we said about Senate in Brazoria County, it's called the Brazos Bend prospect, and the reason I mentioned it now is because it tend like a Robin prospect. We are seeing about 150 Bcfu reserve potential in the prospect, think we will own a quarter of it, it just next month and it's about a 17,000 foot lower freeo , it's got some other lands, but we are blaming that well in South Texas and we will do that next month, and Mack is there anything that you want to comment on that.

The well should spud sometime this month in the next two weeks.

Very good, thank you guys.

The next question comes from Van Levy from CIBC World Markets. Please go ahead.

Good morning, how are you?

Hi, Van.

A couple of questions, CapEx $40m, but it doesn't seem, I guess 10%, did you say production growth this year?

I said some day.

Some day. So it doesn't seem that the production skipping up that much, and I thought that was kind of the view before hand, what was your budget?

Got it. Must be increasing the budget will affect 2005 production.

Okay, so do you have a sense of maybe an exit rate going out of 2004, Roland?

Well, let me just let you know, not including the impact of this budget because we are not really projecting any production from the new wells, Mack's drilling until 2005 -- because they're not to be online much of this year, but we are still looking productive rate, the neighborhood of a $140m as they to achieve the kind of production growth this year. I think, we will be in a better, we will be in off better shape for next year's production growth, we have an additional activity in East Texas and that's really been the region, that's been -- we been trying to offset that declines with the capital another areas.

Yes. Those -- one of the question is that effects of the decline in the second quarter and I think you answered it just with the selective activity.

With very little activity and it's for quite sometime and even though has a lower decline rates in different regions, I think turning that is our growth area that would make the ability that increased production 2005 much easier because what we haven't compensate with the make ups for production declines and our margins reserve area with that gap on other region.

And a lot of it Van will be more predictable. As you noticed, we've got $20m as a CapEx budget for East Texas, North Louisiana. Then we've got $20m for South Texas, we also have $20m for the Double A area. So, we're going to spend a lot of money onshore, and it's lot more predictable for the production rate versus the Gulf, and really the Gulf is a timing issue. So we're trying to do that.

Okay. And then just some curious economics in East Texas, where did you get your defining costs and given a 550 gas price, where there typical, rate of return would be there, and I guess I'm just, I'm asking that because it seems that you just wake up one day, you've the safest position and now you're drilling it, maybe it was marginal at 450 and 550, it's much more economic?

It's a good question.

Over the last two years, we've had a number of prospects identified on the basis of tier levels, tied to commodity, pricing of course, and then the cost to drill and complete. And after reviewing all the data over the last two years, other operators have come in to the individual areas and as I mentioned earlier there are nine of them that we're going to drill with them. They've drilled on tighter spacing offsetting our acreage, we have those results. My long story short, running the economics on $1.2m drilling complete, one to one and a half be, you tier your commodity pricing between $4 to $6 gas and you're generating 30% to 60% rate return minimums depending on the area. So --

Even the success rate of 90%?

Absolutely.

Okay. So, even at the $4 deck, it was -- given the certainty of success, 30% risk adjustments?

Absolutely, and just a matter of allocation of capital at that point.

Remember for the last probably 16 to 18 months, Van we've always said here's our CapEx budget in the area that we could cut back in that the acreage will still be help our production with the East Texas, North Louisiana. So, we cut it back there intentionally, so we could pay down our debt and now what's happened we've repaid it down. We think we can get it to 40% by year-end. We can accelerate, materially accelerate our East Texas, North Louisiana program without having to pay hundreds of millions of dollars to acquire the acreages to drill the wells.

Okay. Sequentially DD&A is down about 39 I think, about 48. How does that happen, and I guess likewise just lifting that severance taxes down to about $0.81?

Now that's really a function of the newer production coming on. In the first quarter, it was actually -- January was a real live production month and the operating costs were pretty much down their any way, and first quarter was a little unusual. But second quarter, as really as we said, as the bigger properties came online, they have lowered depletion rates and the operating cost is about the same.

What primarily were those properties that suffer with them? Did this affect a lot of it's rights, so it's a --

Individual where everything --

Your DD&A pulls by a field, right?

Our field areas. The field is contributing to a larger percentage of production in a quarter than a different quarter, then its rates

going to have a bigger influence, and we have 150 different call centers. And some of the nearest stuff in the Gulf is now -- make up a bigger percentage of the Gulf production versus the older Ship Shoal property in a more favorable operating costs and DD&A.

Okay. Last question, I guess this is for Jay. Jay, understand the -- I want to make sure understand that the Bois d'Arc transaction, you're talking about reducing debt, because you're shifting debts down to that level and then maybe on IPO, but until then you've going to consolidate proportionally. So, when we look at this Company, both from modeling purposes, it looks like it's going to be kind of the same, and I'm curious in terms of legal liability on the debt. Do you really go down to debt-to-cap 40% by shifting it or in fact are you still on the line for say you really can't look it at that way?

We said that we would only -- our debt-to-cap is under 40% after the refinancing of the debt, so actually it hasn't happened now and --

That hasn't changed, really right now Van, when and if we refinance it, we said that we anticipate our debt-to-cap dropping to 40%, and refinancing being that --

We would pay it off and --

And I -- like to put through an IPO or equity?

Fine, that's what.

Okay.

Right, and there is no intention of refinancing with other debt.

Okay. But essentially looking at Comstock pose from sort of Bois d' Arc transaction, whether be an IPO or just a joint venture, the risk to the company in terms of debt, I mean things have not changed that much except for segregation of assets and --

Half of that was paid off Van, I mean, obviously, you mean when its paid -- when it's paid off, the debt is gone. Right now, it's there, so that's exactly what we're stating, right now there hasn't been a change,

Correct. Right now Van, what we've done is we -- what we're trying to do is, we try really to -- we've always had relationship with Wayne and Gary with Bois d' Arc.

Right.

And they have been great creators of wealth for themselves and quite frankly for Comstock stockholders, and they've been rewarded by earning once and we had reported earlier they are in $7.5m of warrants last year alone and we've had this program since 1998, and because we have had about a 10-year relationship with them, we've looked at all of our strengths and all of their strengths, all our of weakness, and all of their weakness and we said, there should be a way to materially improve our relationship and to put all of our assets into a new company unless that company grow and it will help the stockholders of Comstock, it will have the old Bois d' Arc people, they are working interest owners. If we get 300,000 acres of leases in the Gulf, we'll spend tens of millions of dollars on the seismic, we had probably 60 plus prospects, we've got a lot of wells we need to drill and we are kind of constrained right now, we can't drill more. So, if we can create this new company and have another couple of rigs busy drilling wells, and we can increase our interest in the program and protect the value, then we think that's the real way, really to create a new company that is win-win for everybody concerned.

Okay. And do you vision, let's say that you go public -- do you envision Comstock selling shares or just again it's just a financing vehicle to allow you to accelerate and you'll be diluted down with, as they sell new shares to the public?

We would not anticipate Comstock selling any shares period.

Okay, excellent. Thanks guys.

The next question comes from Rehan Rashid from Friedman, Billings and Ramsey. Please, go ahead.

Good morning, Jay.

Hi, Rehan.

Most of my questions have been answered. Just real quick, on the Ross prospect, with Davis-Blackstone, Davis-Blackstone coming in nicely. Any thoughts on further Ross development? I might've missed this, but -- and also in terms of reserve impact from additional kind of discoveries in the Ross area?

Rehan, we have -- this Mack, we have a well that is being permitted right now, it's in the Southern part of the Ross prospect area and we intend to spud that well in the first part of September, and again we've also got the new seismic that is being shipped to us within the next couple of weeks as Jay mentioned, we are going to be evaluating that seismic on the edges of the original seismic, we have some overlap there that will improve the resolution and that will drive our next move in terms of drilling to the Western or Eastern parts of the Ross prospects area. So, that's where the reserve implications could occur.

Got you. On prospect, what have you guys heard about Anadarko's problems with -- whatever they have discovered further down South of .

The information that we have is that they are drilling a second well based on 3D seismic and they spud that well that's already spudded prior to planning the 3D dataset and they are proceeding, obviously.

Which is interesting Rehan, because they're only a couple weeks away from the 3D and I suspect it is, how long ago Mack?

About three weeks ago.

So, we take that as a positive.

Got you.

A dense grid of 2D data there that supports their efforts, so --

Right. And first of all, that their drill was the P&A that caused them sound problems, special problems?

Again, they are extremely tight with the information, but we believe that it was mechanical failure, the wellbore, and it caused them a lot of difficulties in trying to maintain a completion in the well. So, they abandoned it.

How deep would your well would be, and what kind of time, drill time are we talking about?

The Robin prospect is about 19,000 foot well, and drill time would be about 60 days.

And North Robin, is it North or the East and West?

North Robin is going to be drilled from a surface location outside the thicket, and its sort of about 17,500 feet.

Rehan, if you view that map of the Robin prospect, when you go outside the thicket to the Northeast and Northwest side of the Robin. What we've done is, we permit a drill sites on each of those sides, the East and the West. So the location of the rig would be out of the thicket, and it would be a 5,000-foot directional wells, is that right Mack?

Right.

From either side, and which would bottom out underneath the thicket.

And, that 5000-foot is based on an interpretation prior to getting the 3D data's, that we in fact might learn that we are lot closer, our target is a lot closer to the edge of the thicket than originally assumed. But, in the worst cases its 5,000 feet.

Got you. Okay, thank you.

The next question comes from Kelly Krenger from Banc of America. Please go ahead.

Good morning. Couple of questions. First on the Bois d'Arc, the new company, are you targeting, I'm presuming you're targeting kind of a -- some time in third or early fourth quarter for the IPO in that or for refinancing the debt that's down there?

It would be, early as fourth quarter event Kelly is our guess.

Okay, and it sounds like, if you -- say, you don't want to leave the debts down there. So, if you are unable to get some sort of equity financing, I know there is a break up date or a kind of a date, some refers to that you guys can break this thing apart if you want, is that. But there'd be other things you would consider if you cant get equity, would you consider leaving that down there or refinancing the debts down there and try to acquire later or what are your views on of the market isn't there for an IPO?

Well, that's going to be a joint decision that, both sides would have to come to an agreement, but I think, just the -- both sides really don't want to see that in the end of the, we think that pure Gulf of Mexico exploration company doesn't need to carry very much debt if any. And, so I think that, it would be, not just unlikely that -- the two contributors are going to agree that it has some sort of labored entity, that's why there is a break up provision, because that's not the -- we don't think that would be the right thing to do.

Okay. And then secondly, assuming that you do get the new Bois d'Arcs, the new venture goes as planned and you pay off the debt down there. Then Comstock would effectively be left, I think with just to note, since the $175m of notes. Going forward and you're ramping up East Texas, But going forward, if you generate free cash flow, what are your priorities for the free cash flow use in the future, would it to be increase CapEx more, try to have more production growth or what would you guys be looking if they do?

I think, if this is successful as far as the refinancing of the venture debt, which in turn would achieve Comstocks own the delivering goals. Then, there would not be a real need to continue to deliver nor they would be very easy to do it, since all of our debt would be in the public notes. It would be the, most on reinvestment opportunities. We think we have a lot of those, just in our own properties, and that's why we are starting the process of starting up the East Texas drilling because you don't just do that over night. It may take Mack a while to get rigs in place, get programs in place, buy pipes and store it, I mean lot of what we're doing in our budget this year is preparing for the ramp up of next years activity level. But the same time, he is going to be able to get, we should have 11new wells drilled that were budgeted before this year. In the effort of much bigger pace, any alike and then on the results for the first phase of that program, I mean there is potential that it's much larger than a 100 wells, and we'll continue to evaluate that. If you look at, we are expanding, our exploration effort in South Texas and we think there is a lot of opportunities to use the cash flow now that, once that we are known that the debt reduction goals have been achieved and that's not a big part of our business plan.

Okay, and then one last question. It's kind of tough to tell given the way the Company maybe structured at the end of this year depending if Bois d'Arc venture goes as planned or successful, but I think you said earlier you are kind of shooting for anticipating 140m cubic feet a day accelerate at the end of this year, would you anticipate production growth for next year then, what's the incremental money that you're spending on, particularly in east Texas or do you have a kind of a preliminary sense of that, that you want to share with us?

Yes, it's actually harder when you look ahead, but we would be trying to come up with a -- we would like to achieve the 10% to 11%, 12% production growth next year just and that's from using our proportional interest and Bois d'Arc versus a 100%. And we will evaluate if we have enough activity level to do that.

That's the one reason Kelly, right now, if you noticed, we changed over Mack as the COO and we re-evaluated all our acreage position in our three core areas. We have already today, we thought we were increasing our budget in each of the three areas. So, that tells you that we believe that we do have lots of prospects to drill. And you can see that because we had to cut back our budget to last year and part of this year, because we did need to get rid of the 11.25% bonds. And if you look at historical growth, I mean in 2001, we grew our production by about 10%. In 2002, 2003, we are about 7%, 7.5% each of those years and this year we are saying 7% to 8%, which kind of goes back to our historic number. And as Roland said, we always try to see for somewhere north to 10%, if we can do it and we internally believe we have the inventory prospects to push us toward that goal, without having to go out and acquire something to do that. Although, we always look for things to buy, we are projecting that really from an internal growth rate, we are just capitalizing the value of the assets that we already own. Even if you look at today, we've got probably eight or nine rigs running right now for Comstock. We've got 42 wells to be drilled between now and year-end. We've got probably five high-impact wells which maybe all of them here or none of them here, but probably three of those are in the Gulf which are deeper than 15,000 feet. We have got the Shell form out. We've got to Hunt Petroleum deal, we've got some other things in south Texas. We've got ten wells waiting to be connected to sales. So, we are trying to set in motion all of those things that will give us a real good exit rate this year, but really throw us into '05 and '06. So, we'll be a much more predictable company.

Okay. Thank you.

As a reminder, to ask a question, please press star then one on your touch-tone phone. The next question comes from Ray Deacon from Harris Nesbitt. Please go ahead.

Good morning Jay and Roland. How are you? Could you tell me what percentage of that 140m a day exit rate part of, do you expect to come out of the Gulf of Mexico?

Yes, that's obviously the biggest driver of the growth, because it's the projects that -- it would be about close to half of our production.

Okay, by year-end?

By the end, and that's -- the Gulf course is ranged anywhere between 40% to, when all these projects are in, we think it's capable of being half of our production rate.

Remember, currently right, we have about 80m a day, shore and the rest is offshore.

Okay, got it. And if you would look at the organic growth beyond -- if you are in the Gulf, once you get to year-end, is there anything left to be hooked up, that's discovered now, that's not going to be in that number?

In the Gulf of Mexico?

Yes, is everything on?

We see right now, all of our projects should be able to be online by the end of the year. And that's actually we've got a --

Yes 13 wells, year-end which is drilled.

Mostly all exploratory prospects, most of the budget remaining is exploratory projects and so the results of that will be stuff for next year.

We've got 13 in east Texas. We have got five in south Texas -- 11 in south Texas. We got 13 in the Gulf and southeast Texas we've got five. So, we've got -- that's the 42 wells and not all of those will be hooked up by year-end of course. Lot of those will be driven into first and second quarter five.

Okay. Got it. And where are the three wells that you are going to drill in Southeast Texas in the Double A Wells area that are not testing robin prospect? Are those --

There are kind of area wells like Panola 3 is the one for sure that's been you are seeing.

Okay

They are South, remember they are South of Double A, and the Northern part of --

They are more in Ross area, right.

Okay, so it's sort of on the edge of the 3D that you have now. Okay.

Yes. The edge of the old 3D, that's exactly right, and as they run in the middle of the new 3D.

Right. Okay. Got it.

And that new data what's going to be available they are kind of stalled drilling some of those wells just to see that would enhance hence the location picking for those wells but, it -- when that's in that should help.

And any progress with the seven locations on the Native American lines there that?

That is supposedly progressing, although we're just not accounting on those been in this year's budget anymore. I think it's a good chance, this will be things that are going to be drilled next year, I mean with the agreement to settle up all those lease issues is actually requirement that we drill those wells. So, we still want to drill. But good chance will be to able to add those next year's budget, but we just -- given a slow as that thing is moving, we just don't see it happening this year.

Okay. Got it.

That could always change.

Right. And when you, I guess, when the Bois d'Arc becomes a public Company, what percentage ownership we will Wayne and Gary have of -- I know they have a pretty sizeable stake in Comstock now, but how will that work, will some of that be converted into -- will it remain all Comstock shares or will they have a?

I can't discuss what they own personally, but they would obviously own shares in Comstock, they own options in Comstock, and they own the rest of -- they own largeable size of Bois d'Arc Energy. So, that is really -- yes they own lots of all three of those.

Okay, all right. And --

It's now conversion of the old though anything in this new Company those are told outside separately about them.

Right, okay. Got it. And I know, they didn't have formal reserve reports put together, but I'm just trying to get some sense of what would you guess as far as kind of a three-year F&D cost for the Bois d'Arc Company. Do you have those numbers yet or?

No. We don't have those number yet, and we are trying to draw one out. I think if you look at our -- look at our Gulf of Mexico results, I mean we are a mirror of them, other than the big acquisition we made from and which the ups didn't have. I would think their results, that their F&D cost will be more favorable than ours.

Right. Okay.

I'll have that within the next month or so, when as and we are completing GAAP-based audits on the Bois d'Arc operations from the last six years.

Okay. Got it.. I know -- you haven't hedged at all the past couple of years, it's worked out well, but you got a 640 scrip for next year for gas are you looking at that at all?

we are going to look at, yes, not so much for this year, but I think if you look at -- I think -- will consider looking at next year's hedging Madison gas that relates to capital we invested in East Texas plus as we have pointed out with their discussion with Wayne earlier that, it's a parental program is definitely probably 450 plus gas to deliver acceptable returns. It's not a program that you would undertake at $3 gas, and that's -- from that standpoint compared to the rest of our drilling budget, which isn't that price sensitive, it will be price sensitive. But I thought we might -- we've take into account, look at the materiality of dollars going into the area in the 2005 budget, see if we want to support some of that hedges.

Okay.

For this year we don't think it's enough, given the year is more than half way through and others are just starting the ramp up program. I don't see us putting in a spot of position for this year. This production really went beyond mostly into next year anyway.

Okay. Got it. And output is that roughly seven or eight you will try to run through '06, is that about right?

All right, thanks a lot guys.

Thank you, Ray.

Gentlemen at this time there are no additional questions. Please go ahead with any closing comments.

Again, we would like to thank you. It's a long conference call, it is about an hour and a half. There is lot of information, there is a lot of good happening. Again, I think we are -- you can see we demonstrate that we are growing the Company, and now it's a good season than ran. I want to congratulate Mack for being the new COO. I think you will see our onshore growth really kind of blossom. Mack has been here 7 years and I am glad to name him the COO. Thanks for all your questions.

This concludes the Comstock Resources teleconference. Your conference has concluded. You may disconnect at this time.