Comstock Resources Inc (CRK) 2005 Q2 法說會逐字稿

Good morning, ladies and gentlemen. And welcome to the second-quarter financial results conference call. [OPERATOR INSTRUCTIONS] Later we will conduct a question-and-answer session. Please note that this conference is being recorded. I will now turn the call over to Mr. Jay Allison. Mr. Allison, you may begin.

Thank you. Welcome, everyone. Welcome to Comstock Resources' second quarter 2005 financial and operating results conference call. You can view a slide presentation during or after this call by going to our Website at www.comstockresources.com and clicking "Presentations." There you will find a presentation entitled "Second Quarter 2005 Results." To change the page in the presentation, click on the arrow on the page. I am Jay Allison, President of Comstock, and with me this morning is Roland Burns, our CFO, and Mack Good, our Chief Operating Officer.

With this call I will review our 2005 second quarter financial and operating results, as well as the results of our 2005 drilling program. We will also discuss the transactions we completed in the second quarter, including Bois d'Arc's IPO, and our $191.6 million acquisition of properties from EnSight. Our discussion today will include forward-looking statements, within the meaning of securities laws. While we believe the expectations of such statements to be reasonable, there can be no assurance that such expectations will prove to be correct.

Page two, 2005 second quarter highlights. Strong oil and gas prices contributed to strong financial results in the second quarter of this year. Our revenues reached $68.5 million, and we generated EBITDAX of $53.8 million and operating cash flow of $47.3 million. We also generated a profit of $12.7 million or $0.30 per share. Our net income was hampered by the writeoff of the dry haul at Big Sandy, which reduced our net income by $9.2 million or $0.22 per share. Apart from the Big Sandy, our drilling program has been successful with a 95% success rate, having drilled 42 wells with only three dry holes.

We closed three major transactions in the second quarter that have transformed the Company and positioned it for future growth. The $191.6 million EnSight acquisition added 18 billion cubic feet equivalent per day to our production and added 424 drill sites to our onshore drilling inventory. To strengthen our balance sheet, we sold 4.5 million shares of stock at $27.50 per share in a public offering. On May 11, Bois d'Arc closed its initial public offering at $13 per share and is now trading on the New York Stock Exchange. Comstock owns almost 30,000,000 shares of Bois d' Arc, which has a current cash value of slightly under $0.5 billion at the close of business yesterday.

Page three. Average daily production. Production in the second quarter of 2005 averaged 130 million cubic feet equivalent per day, which has increased 5% from our daily production level in 2004, second quarter. And has increased 10% from our first quarter production rate of 118 million cubic feet equivalent per day. Our share of Bois d'Arc Energy's production averaged 38 million per day in the second quarter. Bois d'Arc's production averaged 72 million per day, which was up 5% from the first quarter level.

However, our ownership in Bois d'Arc decreased to 48%, as a result of Bois d'Arc's IPO in May, which accounts for the decrease in our offshore production. Our onshore production averaged 92 million per day, which was up 16% over our onshore production in last year's second quarter. And was up 19% from our first quarter production. For the remainder of the year, we are expecting production to increase both onshore and offshore to approximate 145 million cubic feet on the combined basis in the third quarter of this year, and 154 million cubic feet per day in the fourth quarter of this year. Increases from the offshore production rate relate to new production from Bois d'Arc they expect to bring on line. The offshore gains were driven by the EnSight acquisition and the east Texas drilling program.

Page four, average daily production. Looking at just our onshore production, we averaged 92 million cubic feet equivalent per day in the second quarter. Our east Texas, north Louisiana region averaged 38 million per day. Our southeast Texas region averaged 21 million cubic feet equivalent per day. And our south Texas/other regions averaged 33 million per day during the second quarter of 2005. The gains in east Texas/other regions were particularly due to production from the EnSight acquisition, which we closed on May 12 of this year.

Southeast Texas continues to show declines with no new production coming online this year. We plan to drill two developmental wells in this region to help offset some of that decline. For the remainder of the year, we are expecting production to increase to approximately 103 million cubic feet equivalent per day in the third quarter and 109 million per day in the fourth quarter. The increases are due to having the EnSight properties for a full quarter, and new production from the east Texas 67 well drilling program underway.

Page five, average oil price. Oil prices have surged upward this year. Our average oil price increased 25% in the second quarter of 2005 to $46.74 per barrel, as compared $37.55 per barrel in the second quarter of 2004. In the first half of 2005, our average oil price increased 30% to $47.26 from $36.24 in the same period in 2004.

Page six, average gas price. Natural gas prices have increased also, but not as much as oil prices. Our average gas price increased 15% in the second quarter of 2005 to $6.66 per Mcf as compared to $5.77 per Mcf in the second quarter of 2004. In the first half of 2005, our average gas price increased 13% to $6.46 from $5.71 in the same period in 2004.

Page seven, oil and gas sales. To best compare oil and gas sales, we have broken out onshore and offshore, we have also included the 13.4 million in sales that we did not pick up from Bois d'Arc as a result of changing to the equity method. For the second quarter of 2005, our oil and gas sales increased to $81.9 million, which represented a 15% increase from 2004's second quarter oil and gas sales of $66.5 million. For the first half of 2005, our sales increased 20% to $151.8 million, as compared to the same period in 2004 sales of $127.2 million.

Page eight, EBITDAX. Our earnings before interest, taxes, depreciation, amortization, and exploration expense and other noncash expenses increased 2% in the second quarter of 2005 to $53.8 million, as compared to $52.5 million in the second quarter of 2004. For the first half of 2005, our EBITDAX increased 10% to $108.8 million, as compared to EBITDAX for the same period in 2004 of $98.7 million. Note, using the equity method of accounting for Bois d'Arc, we no longer pick up any of Bois d'Arc's EBITDAX starting May 10.

Page nine, cash flow. Our cash flow from operations increased 4% in the second quarter of 2005 to $47.3 million as compared to cash flow of $45.4 million in 2004's second quarter. For the first half of 2005, our cash flow increased 13% to $93.9 million as compared $82.9 million for the first half of 2004. Note; using the equity method, we did not pick up an additional $10.3 million in operating cash flow related to its share of Bois d'Arc's operations.

Page 10, earnings. For the second quarter of 2005, we reported net income of $12.7 million or $0.30 per share as compared to net income of $18.7 million in the second quarter of 2004 or $0.52. The Big Sandy dry hole of $14.3 million, which was written off in the second quarter, cost us $0.22 per share. In the first half of 2005, we had net income of $28.6 million or $0.72 per share as compared to net income of $18.7 million or $0.52 per share in the first half of 2004.

Page 11, second quarter cost per mcfe. With rising oil and gas prices, our unit costs have been increasing also. Our lifting cost per mcfe produced increased $0.19 in the second quarter of 2005 to $1.29, as compared $1.10 in the second quarter of 2004. Our G&A per mcfe, excluding stock based compensation, increased $0.09 in the first quarter of 2005 to $0.24 as compared to $0.15 per mcfe in 2004's second quarter. Our depreciation, depletion and amortization per mcfe produced, increased $0.24 from the second quarter of 2005 to $1.59 per mcfe, as compared $1.35 per mcfe in 2004's second quarter.

Page 12, six months cost per mcfe. Our lifting cost per mcfe produced in the first half of this year increased $0.12 to $1.26 as compared to $1.14 for the first six months of 2004. Our G&A per mcfe, excluding stock based compensation, increased $0.08 in the first quarter of 2005 to $0.23 as compared to $0.15 per mcfe in 2004's first half. Our depreciation, depletion and amortization per mcfe produced, increased $0.19 in the first half of 2005 to $1.59 per mcfe, as compared $1.40 per mcfe in the first half of 2004.

Page 13, the EnSight acquisition. On May 12, we closed our previously announced acquisition of producing oil and gas properties from EnSight Energy Partners, which is based in Shreveport, Louisiana. We acquired 240 active wells, which were currently producing 18 million cubic feet equivalent per day. The acquisition included 53,000 gross acres, in 45 separate fields. The acquisition also included 424 identified potential drilling locations on these properties, which will give us the opportunity to create substantial value from this transaction beyond the pre-reserves being acquired. Our acquisition price was $1.60 per mcfe based only on approved reserves being acquired and not giving any value to the probable and possible reserves that we have identified.

Page 14, EnSight reserve profile. We estimate that the acquisition has proved reserves of 120 bcfe. 57% of the reserves are natural gas with 43% representing 8.6 million barrels of oil. The reserves are 37% developed and 63% undeveloped. The undeveloped reserves in the acquisition primarily relate to 96 proved, undeveloped locations. We will operate 92% of the proved reserves being acquired in all of the probable reserves. In addition to the proved reserves, we have identified an additional 85.6 bcfe of probable reserves, which are attributable to another 133 drilling locations that we have not classified as proved.

Page 15, drilling expenditures. We spent $89 million on our drilling program in the first half of this year as compared to $72 million for the first half of last year. We drilled 42 wells, 39 of the 42 wells this year were successful with only three dry holes. We spent $35.4 million to drill 39 development wells, all of which were successful. We spent an additional $8.3 million for workovers and recompletions and other development costs. We spent $16.2 million on our exploration program. $12.6 million was spent to drill three exploratory wells. Only one of which was successful. We spent $56.3 million on our onshore properties as compared to $18.5 million in the same period in 2004.

$32.7 million was spent on our east Texas drilling program, with $13 million on the Big Sandy well. And the balance of $10.6 million in south Texas/other regions. Our share of Bois d'Arc's expenditures was $32.7 million as compared to the $53.5 million we spent on our Gulf of Mexico properties last year. In the second half of the year, we will no longer reflect our share of Bois d'Arc's capital expenditures. In the last half of this year, we plan on spending a total of $57 million on drilling expenditures allocated as follows; $43 million on our east Texas drilling program. 4 million to drill two developmental wells in southeast Texas. And $10 million in south Texas/other regions.

Page 16. East Texas/north Louisiana region. Production averaged 38 million per day in this region in the second quarter of 2005, as compared to our first quarter production rate of 30 million per day. The increase is attributable to the EnSight acquisition, which is included for a portion of the second quarter and to our east Texas drilling program. We drilled 28 successful wells, 20.8 net to us in this region in the first half of this year. The wells drilled have an average production rate of 1.6 million cubic feet equivalent per day per well. We are currently operating three rigs in this region and are working to add a fourth rig by the end of the year.

Page 17, southeast Texas region. Our production averaged 21 million cubic feet equivalent per day in 2005 second quarter in this region, which decreased from first quarter production of 24 million cubic feet equivalent per day. We hope to turn the decline around when we drill two developmental wells in the Indian reservation later this year. As soon as our settlement is approved by the Federal Government we will drill these wells. As we discussed earlier, we drilled a well to test our Big Sandy prospect in the south of Double A Wells field. It was not successful and was written off this quarter. We plan to rework the seismic data to determine if the Robin prospect is impacted by the failure of Big Sandy. We will continue to work toward getting a permit to allow drilling in the Big Thicket to allow Robin to be tested at a more affordable cost than the Big Sandy well.

Page 18, south Texas/other regions. Our production averaged 33 million cubic feet equivalent per day in 2005's second quarter in our south Texas/other regions, which was up approximately 10 million cubic feet equivalent per day from production in the first quarter. The EnSight acquisition accounts for much of the increase. We drilled 13 wells in our south Texas/other regions in the first half of 2005. 12 of these wells were successful, and one was a dry hole. The six wells in south Texas have been tested at a per-well rate of 2.6 million cubic feet equivalent per day. The most noteworthy of these wells, is the third well drilled in the Javelina Field, which had an initial production rate of 4.8 million cubic feet equivalent per day. Two wells drilled in Arkansas, in the Gragg field have been tested at a per-well average rate of 2.2 million cubic feet equivalent per day.

Page 19, onshore drilling locations. After completing the EnSight and Ovation acquisitions, we have an extensive inventory of low-risk drilling locations on our onshore acreage. We have 601 locations in the six states shown on the chart on page 19. This is the most drilling locations of this quality that we have ever had in inventory at any point in our corporate history. 201 of the locations are proved locations where we have reserves booked. The remaining 400 are either probable or possible locations. 469 of the locations are in Texas and Louisiana, areas that we have been drilling in for over 10 years. In this high gas price environment, we believe that the drilling of these locations will provide us an excellent return on our investment. The drilling program will continue to be the major source of our onshore growth for the remainder of this year and into 2006.

Page 20, Bois d'Arc Energy. As was reported today, Bois d'Arc has had an excellent drilling result so far this year. Bois d'Arc has drilled 12 offshore wells, 10.2 net, in the Gulf of Mexico to date in 2005, with a 92% success rate. Five of the wells were exploratory, and seven were developmental. All of the exploration wells were successful and six of the seven developmental wells were successful. We expect that the reserves added as a result of these 11 successful wells are expected to more than replace Bois d'Arc's full-year 2005 estimated annual production.

The Paddlefish and Laker Prospect wells are the most significant discoveries made this year. We own 100% of both of those wells. The first Laker well was placed on production in July at a rate of 5.9 million cubic feet equivalent per day. The Paddlefish wells at Ship Shoal 92 are expected to be on production in September. Other successes include three discoveries at Ship Shoal 98 and 99 and a deep well in South Pelto five. The South Pelto well was placed on production in May, at a rate of 7.1 million cubic feet equivalent per day.

The other two wells are expected to be on production in the third quarter. Bois d'Arc is currently drilling two offshore wells and has one other rig involved with the recompletion work at Eugene Island. The South Timbalier block 75 well, the OCSG 22738 number two well is currently drilling to test our high potential Doc Holiday prospect. And a second well is currently being drilled at Ship Shoal 111 to extend the Laker prospect discovery made earlier this year.

Page 21, capitalization. At the end of the second quarter, we reduced our debt to $307 million as compared to $429 million at the end of the first quarter. Our equity has increased to $516 million, from $381 million at the end of the first quarter. The result is a dramatic change in our debt to total book capitalization, which has improved to 37% as compared to 53% at the end of the first quarter. In early April, we sold 4.5 million shares of common stock in an underwritten public offering for net proceeds of $121 million to fund part of the EnSight acquisition. Proceeds from the initial public offering of Bois d'Arc allowed Bois d'Arc to repay the $158 million owed to Comstock. We are now positioned for growth and have the strongest balance sheet in our corporate history. In addition, our stake in Bois d'Arc has a market value slightly under $0.5 billion, compared to the $277 million that we invested in it.

Page 22, 2005 outlook. Our onshore drilling budget will be approximately $115 million this year, which is more than double the $55 million we spent on our onshore drilling program in 2004. The increased investment we are making onshore in east Texas should provide a predictable increase to our onshore production level this year. In combination with the EnSight acquisition, our onshore production should increase by 20% this year over 2004. We have 601 low-risk drill sites to support our growth in 2006, and future years as we continue to expand our onshore drilling program. Our investment in Bois d'Arc Energy is performing very well with an outlook for strong reserve and production growth this year. With the common stock offering and the repayment of our loan from Bois d'Arc, our debt now is 37% of our total capitalization, giving us a strong balance sheet to support future growth. And with that, let me turn it over to you for questions.

Thank you. [OPERATOR INSTRUCTIONS] Rehan Rashid is online from Friedman, Billings. Please go ahead.

Hi, Jay. Could you maybe give a bit more color on the risk profile of this 2P and 3P inventory that you talked about? And maybe focus a bit more on your east Texas program and how it could look like next year?

This is Mack Good, the risk profile of the pud inventory that Jay mentioned is - - has a substantial 2P component, obviously. We're in the process of firming up literally dozens of locations. They will be converted into the proved category, obviously, with drilling success. But the risk parameters that we're using currently, is between 30% and 60%, probability of success on the 2P side. But that's a dynamic that changes as the geologists and engineers work the inventory. And we're very rapidly getting comfortable with improving the chance of success for a number of those 2P puds as we get the technical work complete. With regard to the east Texas program and outlook through the remainder of the year; with the three rigs that we're currently running, as we've drilled in the respective areas, we've managed to reduce the drilling complete time curve by 12 days versus the prior average in early 2004.

That's a substantial decrease, and it's testimony to the number of talented people that we have working in the program here at Comstock and with the service companies that we've formed various alliances with. And that has allowed us to achieve a plus-50 well drilling program with a three to four rigs working type approach. Now we're - - as Jay mentioned, we're currently seeking, adding to our rig inventory. And we feel like we're fairly close to being able to do that. We don't think we can move that fourth rig in until deep into the third quarter. But that will allow us to drill some of these 2P side puds that we really feel confident about. And in addition, we're looking at gaining additional rigs for the Mississippi program, which is a different subject.

Remember Rehan, with EnSight we had roughly 96 proved undeveloped locations. And we said that we'd put a chart out on this when we sold the equity several months ago. That we would drill 15 of those wells this year. And then we drill the majority of those locations next year and the remaining three years out. But really our goal is for every well we drill we would add another proved undeveloped location with that acquisition. At least for this year, next year, and really a lot of that philosophy holds true for the east Texas program without the EnSight acreage.

On - - you gave us IP rates of 1.6 million a day. How is this comparing to your past results, and also from a reserve standpoint? Do I remember 1.2 to 1.5 bcf as a number to think about?

Correct.

With an NRI of about 56%?

Yes, sir. And the program is meeting expectations with respect to performance and costs.

I'll hop off and come back for later. Later for questions. Thanks.

Ron Mills from Johnson Rice is on the line. Please go ahead.

Can you just walk - - of the 600 potential drilling locations, can you give us a rough estimate as to how many of those are east Texas relative or versus your southeast Texas and other - - and south Texas areas?

Yes, we've got a chart to break that out, Mack?

Right. It's I believe it's in the exhibit. In Louisiana we have a total of 54. And in Texas, we have a total, this is gross, of 415 puds. In terms of the proved percentage in Louisiana, 39 of the 54 are proved, and in Texas 87 of the 415 are proved. And I might mention in Texas, we're very rapidly, as I mentioned to Rehan, getting comfortable with assigning a very low-risk number to a large proportion of the 2P, 3P pud list in Texas.

And are you experiencing anything in east Texas? I'm assuming - - are you going solely up there in the Cotton Valley, or are you also - - is it also Travis Peak potential?

Yes, sir. We have both reservoirs targeted primarily in the east Texas program to date, We've drilled Cotton Valley wells. And with the significant number, four to six stages in each completion. And that goes back to my earlier statement about compressing the timeline on drilling to allow us a little more time to frac a greater number of stages. But the bottom line is an improvement of 10 to 12 days on the timeline from start of project to sales.

And from an activity standpoint, in east Texas this year, I think you're going to drill 65 or so wells, which is up pretty significantly from last year. I don't recall the number of wells you drilled. But as you look ahead, do you have - - and to the extent you can add the fourth rig, what kind of activity levels do you think you could end up drilling up in east Texas next year?

Well, it's certainly based on rig availability and service availability. And in east Texas, the demand for services is quite high, as you know. But we have obviously a large inventory to drill. We've evaluated up to 70 locations to date that we want to target for next year. And that number is growing rapidly. So the governor will be, of course, set by the CapEx budget. Also, a determinant will be the rig availability and service availability to get that number of wells drilled and completed. We're in discussions with various drilling rig vendors and suppliers and service providers for next year's program right now.

In terms of take the service side out of the equation where the laying up of frac improves and whatnot has been tight. In terms of infrastructure, do you have any constraints from an infrastructure standpoint that would be limiting your drilling and/or your production growth in the east Texas area? Or are you in pretty good shape?

I think we're in pretty good shape but that's not to say we don't have problems in that regard. I think every operator that has a real active program is going to have issues to resolve. But the purchasers, the - - those parties that own the infrastructure apart from ourselves, of course, they're ramping up the development of their infrastructure to accommodate the additional activity, not only by Comstock, by other operators, as well. So we feel pretty confident that the majority of those issues will be resolvable.

And we have, Mack you might address this, didn't frac like 28 wells last - -?

Yes, we had 28 simulation program jobs done in July, which is just almost one every day. We will approach that same number this month. The program activity by Comstock is historic, obviously. We're achieving faster drilling, faster completing times, and with cost structures increasing, we're trying to be very careful with our per-unit cost. So I feel good about the overall cost structure and performance at this time. We're trying to build the 2006 program and set costs so that we know going in what the bracket will be in terms of cost. We feel, as I mentioned, pretty confident about the performance issues.

Ron, what we try to do is, remember, if you look at 2000, 2001, 2002, 2003, you combine all four of these years, and we've been active in east Texas since 1995, we're going to drill more wells this year than we drilled in those four years combined. And then what we try to do is we try to add to those locations by the EnSight and the Ovation acquisition. Then we try to be accountable to you and others by listing those onshore drilling locations either by 1P, 2P or 3P both on a gross and net basis on page 19 of the presentation. And then, we've attempted to add four rigs. Well we have been sporadic with the fourth rig. But what Mack has said that he's reduced the number of days it takes to reduce one of these drills by 12 days. So we've kind of made up for a little bit of that loss.

And how long does that typical well take you to drill now?

Currently it takes about 15 days. And the completion time is taking about the same number of days. And we're testing in between stages, as well, in order to get performance criteria for subsequent work in other wells. I'm pretty pleased with that time curve. I don't think many operators have been able to beat that.

And then with Big Sandy/Robin, just if we could kind of a quick recap in terms of it doesn't sound like the Big Sandy necessarily has condemned Robin. But is that safe to assume that to the extent you continue to look at that that that's definitely going to be more of a late 2006 event if any depending on the ability to get a vertical - - or a permit that would allow a vertical well bore? And is it also dependent on additional seismic work based on using the knowledge that you learned from Big Sandy?

All of the above, yes, sir. Without a doubt, we're evaluating the acquired from Big Sandy, and we'll be assessing its impact on the overall geological and geophysical interpretation. We certainly do need a Big Thicket permit to drill a vertical well. It's not cost effective nor is it desirable to drill directional in Robin, if we were able to justify drilling it at all. But at this point we're in the interpretive mode. We're reevaluating and reassessing the geological model.

We think if we had drilled a vertical well at Big Sandy, we would have probably saved another $5 million to $7 million versus the directional well because we probably wouldn't have gotten stuck like we did. So what we're trying to do now is, as Mack said, we're reprocessing everything, we're looking at it. If you remember years ago, like 2000, 2001, the first stepout that we had from AA to the south was what we call our Vastar Well. And we had $5 million or $6 million in it. It made 1 million a day. Effectively it was a dry hole. And then from there we stepped out two years later after we reprocessed everything. We had our Hammond No. 1 well, which was our $20 million-plus-a-day well. So historically we've run into a problem every time we've stepped out. We've been successful for the most part. We did hit a dry hole at Big Sandy. We haven't lost any faith in Robin but we're not going to go spend money unless we're comfortable that we have a decent chance of making a discovery.

But from a geologic standpoint, did you find what you were looking for and the sands were just tight? Or was it just - - were the sands just not present?

In the upper Woodbine, the sands were absent. And in the lower Woodbine, the thickness and the quality of the sands were found to be noncommercial. But we did find sands. And the seismic reinterpretation and the remapping will change the picture as far as Robin is concerned. And we'll just see how much it changes.

Okay. I'm going to let someone else jump on. I may get back in queue. Thanks.

Larry Busnardo from Petrie Parkman is online. Please go ahead.

Good morning. Given your inventory of projects that you have and the success that you've had up to date in east Texas, what production growth rate do you think you could achieve next year? And then what CapEx budget would be necessary for that?

A lot is going to depend on the rig availability, as to - - but we haven't set production goals for next year. But, our targets would be to try to achieve, somewhere north of 10%, 15% pipe production growth with the program if it can be supported with our cash flow. This year onshore, we're really, we're taking an inactive area almost, and then growing it with an acquisition to get the larger growth. Next year, just if we can have a 10% growth in that area, just from the drill bit or even 15%, that's kind of what our target would be. But it's early yet for where we're going to say that we have everything in place to deliver that.

Is the goal to maintain capital spending within cash flow, or were you - -would you be willing to overspend cash flow?

I think it would be to keep capital expenditures in line with cash flow. And historically, we typically have underspent our cash flow. At least on the drilling side. And used the excess for acquisitions or debt reduction. And that's probably what we'll continue to do. But with the larger production base and strong prices, the cash-flow numbers were - - their growth next year will dictate, that we'll need to have a much larger program just to keep the same relationship.

Okay. And then just on a broader topic. Just strategically, again, given the inventory assets you have, are you comfortable with what you have for right now? Still looking for acquisitions? Do you feel like you need to make an acquisition to kind of keep the portfolio stocked with development projects?

We - - corporately every year we never stop looking for acquisitions. We have a couple of men that that's all they do. I mean, we never plan on buying anything. We never announce when we're going to buy x amount of dollars worth of production every year. But we do, as far as currently do we have anything we want to buy? The answer is no. You know, can that change next week? It could. But our business plan does not show that we'll buy anything between now and year end.

Okay, great, thanks.

Thank you.

[Paul Cho] from Steadfast Financial is on the line. Please go ahead.

Hi, I just had a few questions. In terms of your production guidance for the third and fourth quarter, it appears to be lower than, I guess, your previous presentation. I was just sort of curious about that. Was that rig available or was that something else?

Mostly we've revised downward a little bit the southeast Texas production with the higher declines that we're seeing. We've also continued to push back the development wells that we had thought originally would be drilled by now as we're waiting for government approval of a settlement with the Indian tribe that calls for those wells to be drilled. That it - - even though everything's in order, it just hasn't come back yet. So, we continue to push that back. So, that's had an impact on that region's production, which is the most of the adjustment that we made.

Okay. And just want to confirm that when you acquired EnSight, it was - - production was about 20 million cubic feet a day. Is that right?

It had peaked at that with the brand new well. But the 18 million a day is exactly what we forecasted.

And EnSight produced - -?

Yes, the 18 million a day that it is producing is exactly how we had forecast it. So, we haven't changed that at all. Just at the time that we happened to talk about it at one time with the brand new flush well on it, it had peaked out at that 20 million a day.

Right. And some accounting questions, I guess. You now account for Bois d'Arc as an equity in earnings. It's a positive contribution, whereas Bois d'Arc had a negative net income. I assume that's because they took their tax charge in the beginning of the quarter before you went to equity?

That's correct. Actually the - - when they took the - - what caused the $108 million initial setup of taxes at Bois d'Arc, which - - because Bois d'Arc Energy was a nontaxable entity before. And its financials were presented on a pretax basis. So on May 10, which is the day before the IPO, was actually when Bois d'Arc in preparation to close the offering, converted to a corporation, and then on that day it - - prior to the IPO happening is when it converted to a corporation under accounting rules. That's what caused us to no longer proportionally consolidate Bois d'Arc. And then we went to the equity method after that event happened. The reason is because Comstock, of course, as it has always recorded income taxes on the income it picked up from Bois d'Arc and the properties before it contributed. Because our financials are on an after-tax basis. So that adjustment that Bois d'Arc took was to put them on a tax basis. Comstock had been on an after-tax basis all along. So, it's - - that's the true net income of Bois d'Arc apart from that entry which is more of a - -.

Accounting true-up?

Yes. And it's just - - really - - that's really - - probably - - should be an adjustment to equity when Bois d'Arc converted. But because of the arcane accounting rules, it - - anything to do with taxes runs through the income statement.

Right. Now I just wanted to make sure, I think we talked about this before. Your equity in earnings of Bois d'Arc that's a direct proportion of their net income. Is that correct?

That's correct. It's their net income as they report it is what we pick up. Our 48% right now. And we started picking that up starting May 11 through June 30. So the dollars, the $3 million or so in our numbers are just our share of the income for that period there. Prior to May 10, we were still proportionally consolidating our share.

At 59% or something, right?

Yes. 59%. So that the ownership change happened about the same time as the change in accounting.

Right. Okay, that's great. Now, I just - - could you just give me your severance and production taxes for the quarter?

Sure. For Comstock, on the - - we had a - - just for the quarter, we had a total of $12.9 million in lifting costs. 3.2 million of that was production, severance taxes, 9.7 were our fixed field lifting costs.

Okay. So you have that for the year-ago period?

For, yes. The - -

Second quarter of '04.

That number was, there was 12.5 million in total lifting costs. 2.7 million was production and severance taxes and 9.8 were the other lifting costs.

All right. Now I guess just one more question is when you acquired EnSight, didn't the properties come with a rig, you said? I think you'd said previously?

Well, what happened there was they had some rigs already under contract that they said as they were going through the - -

Fundraising.

Transaction they said we could use those but we couldn't have them for very long. Just - - and so we used them as much as we could. And then they - - of course, they are still under contract to EnSight. So, Mack, I don't know if we still have any of those.

Yes, one of the rigs is working for us now, finishing up a third well. That rig has drilled. And then it will go back to EnSight.

That's not in your - - Comstock itself has three rigs under contract, isn't that right?

That's correct.

And then you're looking for the fourth rig - -

Right.

Later this year. Which will probably come on at the end of the third quarter, is that right?

Correct. It's our hope anyway.

Okay, all right. Thank you very much.

Thank you.

Ron Mills is online with a followup question. Please go ahead.

Roland, could you walk through some of the cost guidance as we look ahead for production cost and G&A? And if you expect there will be any shift in terms of, the reported taxes versus cash taxes paid?

Okay. You can't figure that from the hybrid accounting we used in the second quarter?

Not quite.

Yes. Looking at if you go away from this quarter, which is the transition to the more onshore results in our reported numbers and the Bois d'Arc numbers just picked up purely in the under equity accounting in a one-line fashion, you really don't - - you actually see - - the cost structure really stays kind of similar. But not for any - - mainly because of some of the lifting costs. And the way EnSight affected our relationship actually it's going to make the numbers look pretty comfortable the way they used to be combined with offshore. But it's purely a coincidence. So, on the lifting side, lifting costs, yes we think we probably averaged about, somewhere around $1.30 per mcfe produced. That includes severance taxes in that number. That could come down a little bit in the fourth quarter with the higher production rate. But given, I think just to kind of to use that similar rate because of the costs are also going up. And that leaves some cushion there for that. Our DD&A rate actually will be about $1.58 just for the onshore piece with the acquisition properties in it. And G&A, we've stopped picking up, of course, part of Bois d'Arc's G&A on May 10. And so that will cause that to come down just a little bit. We're saying our G&A should be more like $3 million a quarter going forward, versus the 3.8 in the second quarter where we picked up a big percentage of their G&A for a little more than half the quarter.

Okay. And then from a tax standpoint, you've continued to defer a significant portion, roughly 90% of your reported taxes. Is that a pretty good rate going forward?

Right. It is on Comstock. We will - - we are adjusting our effective rate up a little bit to 36.3%. That extra from just the 36%, you can - - you probably saw that in the second-quarter numbers. We'd trued that up for the year. That's only because of with the new acquisition properties, we have a significant amount of income in Mississippi. And just to account for that on a go-forward basis, to have - - that would be a little different. That's the only real change to the Company as far as its future income tax operations. The - - yes, we still view that we'll be deferring - - basically the only taxes that we really reflect as current at Comstock will be the alternative minimum taxes that have to be paid that can't be sheltered with net operating loss carry forwards or using IDC deduction. So, that's where you roughly get 10% of the tax provision is typically current.

Okay, and just to clarify a couple of points the production guidance in the third and fourth quarter from onshore is 103 and 109 million a day, is that correct?

Correct.

Right.

And then on Larry's question, the 10% to 15% production growth, was that for east Texas properties alone or is that what you're hoping from an onshore standpoint?

That's a - - you mean as far as 2006?

Yes.

We'd be talking about our onshore production base. And how - - not just that one region. As far as a target. But again, I think we want to wait until we get to later in the year to say that we've got everything in place to deliver that. As far as drilling rigs and a program in place.

Okay. And then from a pricing differential standpoint, excluding hedges, which you don't really have anyway. Except - - unless you have some on the EnSight acquisition.

No we have no new hedging. We do have the collars in place.

Right.

Which are getting close to getting out of the money. We're almost going to go over the cap here at $10 if we don't watch it.

But if you just look at your pricing differential now that you have onshore contribution only, can you give us what your expected differential on gas is from NYMEX and on oil what it is from WTI?

Sure, the acquisition has changed the oil side a lot. So, that's something to look at. But on the gas side it still remains - - we still - - we're kind of forecasting about a $0.10, $0.05 to $0.10 discount at NYMEX on the gas side. And that varies a little bit kind of based on how volatile prices are. On oil, though, we're really experiencing now more of an $8 discount to NYMEX oil prices.

What is COG on that?

The acquisition in Mississippi has a big differential. Now it tends not to have that large of a differential when prices are lower. But in the high-price environment, it's at a - - it's not a real predictable number because of what drives it doesn't really track NYMEX exactly.

Is it because that oil associated with that acquisition is heavier?

Yes.

Okay, okay, thanks, guys.

Thank you, Ron.

Ray Deacon from Harris Nesbitt is on the line. Please go ahead.

I had a question for Mack. Has there been any other activity the lower Woodbine that gives you confidence that you may be able to come some additional reserves there?

By other operators?

Exactly.

Yes. There has been some other activity, but we - - they're still drilling their wells. Dominion is drilling a well. Meridian is planning to drill a well. Dominion to the east of our acreage and Meridian to the west. And we'll be very interested to see the results. We have our precompletion interpretation if you will. We've evaluated that - - those areas that both operators are in. And so we'll be very interested to see what they actually find. And certainly that could impact our interpretation.

Got it. Is their lower Woodbine shallower than yours, or is it to the north -or -?

Yes.

A little shallower. Okay got it.

Certainly is.

And you talked about having - - I guess in the total Company, do you have any rigs locked up beyond east Texas right now?

No. That's the short answer. We have a number of irons in the fire. It sort of gives me an opportunity to talk a little bit about the Laurel field in Mississippi. We're pursuing a rig there to drill several opportunities that we've teed up, and we'd like to get started this year. Laurel is a target rich environment. It's been neglected over the years. We are in the process of improving the infrastructure and the surface equipment so that we'll have the operational efficiencies to handle what we think will be a substantial, additional production. And hopefully, as Roland alluded to earlier in the request for some production guidance, we can get that drilling rig and execute a low-risk series of re-entries of currently shut-in well bores sidetracked to targeted reservoirs that we think hold significant promise.

Okay. How large are those targets usually when you do the re-entries?

Well, there's quite a range really. But just to kind of give you a bracket, estimate, between 0.25 million to 700,000 barrels of oil.

Got it. Okay, thanks, Mack.

Yes, sir.

Rehan Rashid is online with a followup question. Please go ahead.

Mack, going back to east Texas. On the fourth rig by the end of, call it some time in the fourth quarter, and then that should allow you to drill, you said, 72 wells next year give or take?

Well, that's -- really I'd like to drill more than that. Because, we talk about these numbers. The 2P puds, I want to prove those up. And we already have several wells that are currently in the 2P category that we think are very low-risk targets. And so it - - this might be a vague response to your question, but I really want more than four or five rigs in order to drill those opportunities and keep them busy all year long. We've got discussions ongoing with a number of vendors. And I'm hopeful that we can tie down more than just four rigs for execution next year. But the preliminary number right now sitting here this morning is between 70 and 80 wells for next year.

Okay, that sounds like it's a bit below the 100 number we had talked about at some point in time on the east Texas program.

Well, the 100 number, again, depends on; it's more than just drilling rigs. It's - - it does, again, I'll circle back to my original statement. I want to drill as many wells as we can drill with available services. And that goes beyond just the drilling rig question. It also includes suppliers and the service vendors on the completion end. And believe me when I tell you that BJ, Dowel, and Halliburton have no excess capacity as things stand right now. So, in order to get that number of wells completed in the east Texas region, the service providers have to give some indication that they're increasing their capacity.

Okay, thank you.

Rehan, the good part of that, it's not because we don't have the locations. It's a service issue.

Got it. Thank you.

[OPERATOR INSTRUCTIONS] Harry Chernoff from Pathfinder Financial is on the line. Please go ahead.

What are your all-in finding and completion costs for the first half excluding Big Sandy? And also what are they for Bodark, for mcfe?

Well, we don't know the reserves added yet. So, that's a number we won't be able to come up with until the end of the year.

Okay, and the other question, in the presentation on the Comstock Website, prior to the one that appears now, there was a chart that showed the Bodark prospects against the risk estimates, the likelihoods. And there's nothing equivalent to that right now.

Well, that's in our - - see, we don't have - - our corporate presentation hasn't been revised yet. You have just the quarterly results.

Oh, okay. Well, let me make it more concrete then. If you were to put out a Bodark equivalent to the Comstock page 19, what would it show on it on the bottom line?

As far as - - are you talking about where they risk, they came up with really their?

Yes, the 2P, 3P, and what kind of risks you put on the 2P and the 3P?

It's, basically if you looked at their undeveloped acreage and their unevaluated acreage position, and they do have in their presentation have about 1.4 tcf of reserve potential with all of their prospects. Which is - - I think that's 46 prospects, which is more than - - that's probably two years worth of projects. And that's totally on risk, though.

It's Ron. And I think during the road show if you net, net, net risk adjusted, it's 400 to 500-plus bcfe of reserves there. And that's kind of the range that we saw now in discussions.

400 to 500, and that's over two years. Or is that over the lifetime of all the prospects?

Well, that's just those 46 prospects.

That's about a two-year activity level.

Yes. What you've got - - at Bodark you've got three rigs basically under contract. So the goal is just to drill two wells per month. And so for the first six months, there's been 13 wells drilled. So that's basically two a month. And then there's the one in south Texas. So you've got the - - 24 wells was kind of the number of wells as far a goal that Bodark was trying to drill this year. So if you look at the prospects - - I mean, that's roughly two years worth of drilling. Now, again, the beauty of the Bodark story is that those change all the time. As they drill the Laker, as they drill the Doc Holiday, as they drill some of these other prospects, it always seems to grow as far as the prospect number. Even though you drill 10 or 20, 25 wells a year, you still end up with about the same amount of prospects or more at the end of every year, which - - and that's a good thing.

One related final question. Of the five exploratory hits for Bodark and the various development hits, on average or a weighted average, what was the risk on those going in?

I think most of them were probably in the 50% risk category. There was a - - none of those were really deep, higher risk projects. The one - - the deep well drilled was really a re-entry that was a pretty low-risk deep well.

Yes, those were all 50% or maybe north of that.

Right. Those are all - - I think they're now drilling one that - - the current wells that they're drilling, the Doc Holiday would be one of those more high risk, high-potential projects. It's still several weeks away from getting results on.

Okay. That's all. Thank you.

We have no further questions at this time.

All right. Thanks. And thanks for everyone that participated. I know the quarter was kind of a blended set of events, both from accounting and the three transactions. And I think at the end of the third quarter, I think hopefully we'll be a lot more simplified Company and you can really see the growth that we should give you. So thanks for the conference call.

Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may all disconnect.