Comstock Resources Inc (CRK) 2006 Q2 法說會逐字稿

Good afternoon, ladies and gentlemen, and welcome to the 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 this conference is being recorded. I would now like to turn the meeting over to Mr. Jay Allison. Sir, you may begin.

Thank you. Welcome to Comstock Resources' second quarter 2006 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'll find a presentation entitled Second Quarter 2006 Results. To change the page and the presentation, click on the arrow on the page.

I'm Jay Allison, President of ComStock; and with me this afternoon is Roland Burns, our Chief Financial Officer, and Mack Good, our Chief Operating Officer. With this call, I will review our second quarter 2006 financial and operating results, as well as the results to date of our 2006 drilling program.

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

Slide 2. Increased production in high oil prices contributed to strong financial results for the second quarter of 2006. Our revenues came in at $65 million; we generated EBITDEX of $48 million and operating cash flow of $43 million. We also generated a profit of $21 million or $0.48 per share, excluding several special items reflected in reported earnings of $15.6 million.

These items include a $1.3 million unrealized mark-to-market gain on derivatives, a $7.9 million loss on the pending sale of our non-core Kentucky properties, and a $1.1 million provision for deferred income taxes related to a new Texas business tax enacted in the second quarter this year.

Our onshore production increased by 7% this quarter. Our 2005 second quarter reflecting the emphasis we have placed on investing in our onshore properties with the IPO of Bois d'Arc Energy. Bois d'Arc had a solid quarter which also contributed to our bottom line this quarter. Bois d'Arc's production, revenues, and net income were up substantially as the Company continued to recover from the 2005 hurricanes. Bois d'Arc also reported excellent drilling results this year with seven discoveries that will add to its production and reserves.

Our onshore drilling program with a 96% success rate with the 50 wells we drilled in the first half of this year has also been very successful to date, despite the delays we had in getting drilling rigs.

On slide 3, we outlined our onshore production by quarter and by region. Our onshore production averaged 99 billion cubic feet equivalent per day in the second quarter, which is an increase of 7% over 2005's second quarter. We expect our onshore production to increase this year as we are able to connect the wells we are drilling in East Texas, North Louisiana to sales.

We expect our production to grow by 15% this year with the drilling program. The Cotton Valley drilling program that is driving the growth is weighted for the second half of this year. We now have six rigs drilling in East Texas and we expect to have eight rigs running by the end of August. We are working to obtain a ninth rig for this program.

On slide four, we cover our oil prices. Our average oil price increased 28% in the second quarter of 2006 to $58.47 per barrel as compared to $45.63 per barrel in the second quarter of '05. Our average oil price in the first quarter was 83% of the average NYMEX WTI price in the quarter.

For the first half of this year our realized oil price was $56.12, which is up 21% from our oil price of $46.30 in the first half of '05. For the first half of this year our average oil price was 84% of the average NYMEX WTI price.

Slide five shows our average gas prices. Our average gas price increased 3% in the second quarter to $6.72 per MCFE as compared to $6.55 in the second quarter of 2005. Our realized gas price was 99% of the average Henry Hub NYMEX price in the second quarter, which is a substantial improvement from the 87% realization we had in the first quarter as the large differentials from East Texas and Houston Ship Channel and the Henry Hub NYMEX price that shrunk in our back and in their historical relationships.

For the first half of 2006 our average gas price increased 14% to $7.26 per MCF as compared to $6.37 in the first half of 2005. Our realized gas price was 92% of the average Henry Hub NYMEX price for the first half of the year.

Slide six, which shows hedge positions. During the second quarter, we had a mark-to-market gain of $1.3 million to reverse a portion of the unrealized losses we took in 2005 on our hedge position; for the first six months of the year we had a mark-to-market gain of $9.4 million. In 2006, approximately 17% of our gas is subject to a $9.02 ceiling.

Oil and gas revenues, slide seven.

To best compare to a gas sales we have broken out onshore and offshore on slide seven. We have also included the sales that we did not pick up from Bois d'Arc as a result of changing to the equity method. For the second quarter of 2006, our sales from the onshore operations increased 15% to $65 million from $56 million in 2005's second quarter. The increase in production and higher prices account for the increase. Offshore sales increased 10% to $29 million from $26 million in 2005's second quarter.

Now for the first half of this year, our onshore oil and gas sales increased 35% to $134 million from onshore oil and gas sales of $100 million in the first half of 2005. Offshore sales increased 12% to $58 million from $52 million in 2005's first half.

EBITDEX, slide eight. Our earnings before interest, taxes, depreciation, amortization, exploration expense and other non-cash expenses - or EBITDEX - decreased 11% in the second quarter to $48 million as compared to $54 million in last year's second quarter as shown on slide eight. For the first six months of this year our EBITDAX decreased 8% to $100 million as compared to $109 million to the same period in 2005. The decrease is due to using the equity method of accounting for our ownership in Bois d'Arc.

It is important to note that we no longer pick up any of Bois d'Arc's EBITDEX which would have added $23 million to our EBITDEX this quarter and $45 million to EBITDEX for the first half of this year.

Slide nine covers our operating cash flow. Our cash flow decreased 9% this quarter to $43 million as compared to cash flow of $47 million in 2005's second quarter. For the first half of this year our operating cash flow was $90 million, 4% lower than cash flow in the first half of 2005 of $94 million. Again, using the equity method we did not include $21 million in operating cash flow related to our share of Bois d'Arc's operations this quarter which, if included, would have increased our cash flow to $64 million this quarter.

For the first half of this year, if you included our share of Bois d'Arc's cash flow of $42 million, we would have increased our cash flow to $132 million.

Earnings, slide 10. Excluding the mark-to-market gains or losses from our derivatives the loss of the pending Kentucky sale of the charge for the new Texas business tax we reported net income of $21 million, or $0.48 per share, for the second quarter 2006 as compared to net income of $13 million for the second quarter of 2005 or $0.30 per share. We have adjusted the 2005 results presented on this slide to exclude the unrealized gains and losses on derivatives and the onetime effect of Bois d'Arc's conversion from a limited liability company to a taxable corporation and a gain from its IPO in May of 2005.

For the first half of this year, our earnings are $45 million or $1.03 per share, as compared to $29 million or $0.72 per share for the same period in 2005.

Slide 11. With rising oil and gas prices our unit cost had been increasing also. We outlined our onshore cost structure on slide 11. Our lifting costs this quarter averaged $1.47 per Mcfe as compared to $1.29 in the second quarter of '05. Our appreciation accretion and amortization for Mcfe produced increased to $1.84 per Mcfe in the second quarter, as compared to $1.53 per Mcfe in 2005's second quarter.

For the first half of 2006, our lifting costs for Mcfe produced was $1.53 per Mcfe as shown on slide 12, as compared to $1.27 for the first half of 2005. Our depreciation depletion and amortization for Mcfe produced increased $1.85 per Mcfe as compared to $1.50 per Mcfe in 2005.

Slide 13, our capitalization. During the first half of this year our debt has not changed from the end of 2005. Our equity increased by $51 million to $634 million from $583 million at the end of 2005. Our debt to total book capitalization has improved to 28% at the end of the second quarter as compared to 29% at the end of last year.

On slide 14, we break out our onshore drilling expenditures by regions. We spent $92 million in the first half of this year on our onshore drilling program as compared to the $56 million in the same period last year. 48 of the 50 wells drilled in the first half of 2006 were successful with only two dry holes.

We spent $78 million to drill the 50 development wells. We spent an additional $12 million for workovers and recompletions and other development costs and $2 million on acquiring leases. $58 million was spent on our East Texas drilling program. $34 million was spent on our other regions. We still plan to spend for the 2006 year approximately $200 million on our drilling program.

Slide 15, our East Texas North Louisiana region. We drilled 30 successful wells in our East Texas North Louisiana region in the first six months of this year as shown on slide 15. They were drilled in nine different fields. The wells drilled had an initial average production rate of 1.5 [million billion] cubic feet equivalent per day per well.

We currently have six rigs drilling in this region. We expect to add three additional rigs in the next several months to continue to ramp up this program.

Our South Texas region, slide 16. We drilled four successful wells in our South Texas region the first six months of this year. They have been tested at a per well average rate of 5.9 million cubic feet equivalent per day. These wells were drilled in our Ball Ranch and [Havelena] fields.

Slide 17. In the first half of this year we drilled six wells in our big content region. Five were successful and one was a dry hole. We drilled four successful wells in our Laurel field in Mississippi. We participated in drilling six wells in the San Juan Basin in New Mexico. Five of these were successful and one was a dry hole.

Slide 18. Our Gulf of Mexico operations are now reflected in our 48% equity ownership of Bois d'Arc Energy. Bois d'Arc has had successful results from its drilling program so far this year. To date in 2006 Bois d'Arc has drilled seven successful wells out of a total of nine wells drilled for a 78% success rate. The 2006 successful wells included the Laker 5 well at Ship Shoal block 111, a successful extension well in Ship Shoal block 99. A discovery at Eugene Island block 166 and the Steelhead discovery at Ship Shoal block 111 which we discussed in our first quarter conference call.

The most significant discovery that so far in 2006 is the Sockeye well at South Pelto 22. This well was drilled to a depth of 17,686 feet and encountered 184 feet of net pay and seven reservoirs. We expect to complete this well and connect it to an existing operating platform at South Pelto block 22 in the third quarter with production starting up in late August.

Since the first quarter Bois d'Arc has drilled successful wells in Ship Shoal block 106 and South Pelto block 5 which proved out the inward prospect at Ship Shoal block 106 and the Gordo prospect at South Pelto 5.

Slide 19. The 2006 outlook. We are excited about the prospects for ComStock. We expect to spend $200 million on our onshore drilling program this year, which is a 64% increase from the $122 million we spent on our onshore drilling program in 2005. The 96 well Cotton Valley drilling program we had planned for 2006 will drive production growth this year. We have 408 operated low-risk drill sites to support our continued drill bit growth in future years. Our investment in Bois d'Arc energy is performing well with an outlook for strong reserve an d production growth this year. Our debt is only 28% of our total capitalization, giving us a strong balance sheet to support future growth.

I'll now open the meeting for questions.

(OPERATOR INSTRUCTIONS). Larry Busnardo from Petrie Parkman.

Good afternoon. Looking at the East Texas program and the delays that you've had getting drilling rigs, how many wells do you think you can get down? I know you were targeting initially 96, 98 somewhere in that neighborhood. Do you still think you can get that done or are some of these wells going to get pushed off until next year?

Yes what I'll do, Larry, I will turn it over to -- Mack is in here and I've asked Mack to kind of give an overview of the program. How many wells, the rigs, how many different rigs. Is that okay?

That's perfect.

Okay. Mack.

Briefly, the answer to your question is yes. We feel with an eight rig active program in East Texas we can get 95, 96 wells to TD before the end of the year. The program is going well. We are extremely satisfied with the results. We have been frustrated by the slowness of delivery on some of the rigs that we contracted at the end of last year. There've been a number of issues. I won't bore you with the details there.

We are at the point now where we are running six rigs and we have the two rigs that are coming before the end of this month and a ninth rig we are negotiating terms. So we feel with an eight rig program we can get to that count that I mentioned in the 95, 96 well count range. And with a ninth rig, we can easily do that and plus some and just continue to run that program into '07.

Are the two rigs that are going to show up in August is that pretty firm that they're going to be showing up, I mean, could there be a further delay when they actually arrive?

Yes. There's obviously the issue that presents itself until they're here we have to - and we do - keep very close track on the status of those rigs and where they are in the refurb state. We have been assured by both suppliers that those rigs will be on a ComStock location before the end of the month, but there could be issues that we can't foresee; and that is exactly what happened to us earlier this year with the slow delivery of two other rigs that are currently working for us.

But we have no - at this point we have no information that suggests that there is going to be any further delay.

I guess as it relates to production, maybe this is a question for Roland. It doesn't like you've changed guidance for the second half. It looks like it has been adjusted just a little bit. With the delays in the rigs do you think there is much conservatism built into that to account for that? Or I guess -- could that end up being a little bit of a shortfall going forward?

No. We made a big adjustment to that production profile before last quarter, to account for the delay in rigs; so I think since then we are -- there's always -- since then we seem to be getting back on track with the program. So we didn't feel like an adjustment was needed right now. But it's contingent on getting the wells hooked up and all the services, but we were doing -- our production was on track with this forecast with the last month and that we saw so -- so --

Does the current forecast of that have some conservatism built into it or is it risk back for whether there are some additional delays? Just to get things hooked up, I guess, would be -- ?

Yes; there is some conservatism built into that forecast, but obviously the forecast depends upon not only getting the wells drilled, but getting them connected. The production profile that we used in the timing is fairly conservative and attempted to address possible delays. But our goal - as Jay mentioned at the end of the first quarter conference call - is to get our wells drilled and get them completed and connected as quickly as possible. But I think everyone acknowledges the fact that it's a very competitive environment for services, but our forecast does attempt to address some possible delays.

Okay. I think in the next year with eight and possibly a ninth rig, how many wells do you think you could drill next year? In the East Texas program?

We just kind of circle right now somewhere north of 125, 130 wells. We've not come up with a solid number right now because we've got some drilling in the Double AA, we've got drilling in South Texas. We've got some other core areas that we are going to be blending to that. Kind of stuck that number out.

So the nine rigs, they would not be dedicated to East Texas then?

Yes. Eight to nine rigs would be dedicated to the East Texas program.

So it would seem that you would be able to do more than the 125 or 130 then.

Yes we might.

It depends on where you're drilling. For example if you are drilling a 18,500 ft. well in Louisiana that takes two strengths of pipe to get to TD you are going to spend 45 to 60 days per well. If you are in East Texas or Western Louisiana, you can -- we can get these wells drilled to TD in Western Louisiana in 12 days. And in our East Texas average we are getting to TD in 21 days. So again it depends on where you're drilling.

One other comment. When you -- at the end of the first quarter we really weren't pleased with the commitments that we had from the service companies and when the rigs would be delivered. I think we didn't enjoy the first quarter conference call. We tell you that we would increase our interest to try to find some rigs. We've done that.

I think Mack has done a really good job of that and the production guidance we thought at the beginning of the year we might have about a 20% increase; and we did lower that to 15%. We looked at that and we are kind of sticking with that 15% growth. So that, again, is an additional comment to your questions.

Wayne Andrews from Raymond James.

Good afternoon. My questions were pretty much related to rigs and your programs in East Texas, also. But maybe just one more point is, if you had been willing to sign three-year contracts could you have gotten rigs earlier? And maybe one of your issues has been battling some inflation in rig costs. Can you comment on that?

The short answer to that is we could have gotten a rig on a three-year commitment in August, which is this month and we chose not to do that for reasons concerning performance issues for the rig that was going to come into the market that was available to us for bid. We chose to look at some other options and the case in point is, we are moving two rigs in, in August this month.

That's the best information we have available today. On top of the six we currently are running and the program that we forecast last year for this year, assume that we would have seven rigs running by April 1. And that was going to get our program drilled. We had some shortfalls on delivery with the rigs that we had commitments for.

And that's the short story but, yes, the bottom line is if we had signed a three-year commitment last year that rig was a new build and it was going to be delivered to ComStock in August. So we would have had that rig at the first of this month rather than at the end of the month. So a slight improvement.

I think really, Wayne, Mack had an issue with the quality of the server service we were getting from some of the service companies and you pick and choose who you want to deal with and we never gave up that degree of work ethic. And we are pretty picky with whom we want to drill with if it's a three-year contract and we should be, I think.

Yes I agree and I applaud your efforts in trying to work within a reasonable cost frame also. So appreciate your comments. Thanks Mack.

Eric Hagen from First Albany Capital.

In East Texas again, I think at the beginning at the year you said you had evaluated seven [of] 15 fields. Where do you stand now in terms of that?

We drilled on nine of those fields at the end of the second quarter and our goal is to drill on 15 of those 27 fields because one of the things, Eric, we didn't do last year, we drilled the majority of the wells in [Begville] and Blocker. We drilled 48 of those (technical difficulty) wells last year in those two fields.

The goal was to see if we could drill that many wells in a given year because I guess the most wells we had ever drilled was 18 or so and we didn't prove up in any new reserves the program last year. We closed on the inside acquisition. And the goal this year was to work on the inside properties.

We did that for about eight or nine months and then start rolling in that drilling program into the '06 schedule; and because we, remember, we feel like we can add anywhere from 40 to 60 bcfe reserves by the program we have set forth in '06 which means that we need to drill on all those 15 field that we talked about.

What are costs to drill and complete a well running in East Texas now?

Right now our average AFE for a 10,500 ft. Cotton Valley well is 1.8 million per well.

It seems like the IP rates were a little bit higher on your last call. I think you said last time 1.3 and now you said 1.5. Do you think that you know, you have (indiscernible) you are there too now?

Yes in a couple of the fields that we are drilling in in the first quarter we were drilling delineation or evaluative wells for the acreage position that we had; in the first quarter we were able to identify some areas that we felt had the higher potential. And so we concentrated on those in the second quarter.

One final question. In South Texas the Havelena and Ball fields to date I think you drilled -- was it four wells to date or is that in the second quarter?

For this year.

For this year and you had good results in that, Jay. What's your running room in that field and how many locations do you have? Is there a potential maybe to accelerate that program?

In South Texas we've got several opportunities in the Havelena field. We are drilling a well there now and completing a well; and there's a rig that [Avico] has under contract that will stay in Havelena for the remainder of the year - that is my understanding - to drill two puds and an exploration well that can set up additional puds successful and Ball Ranch there are multiple exploration opportunities. We just TD'ed one of those. And we will be testing an interval next week and that rig will stay in all ranch for the remainder of the year drilling two puds and another exploration.

Are those Vicksburg wells or --?

Yes.

Mack might want to go over the 3-D play and the seismic we have; the 80 square miles.

In Ball Ranch we've extended our opportunity to the South through accessing additional seismic; and there's some exploration opportunities to the South that have been identified. Can't really talk too much more about that. In Havelena, we have also extensive seismic cross that field that also is allowing us to identify a number of leads.

Thanks.

Ron Mills from Johnson Rice.

Good afternoon. I don't even know if I want to say East Texas now. With production and I guess, Roland, this would be for you from a guidance standpoint. With production guidance not really changing from -- especially in the third quarter given the delays is it fair to assume that some of your production from South Texas in particular is probably running a little bit ahead of schedule, to make up for some of those delays?

As you saw with the second quarter results, in the South Texas/ Mississippi area there's a tiny little head, program, East Texas. We factored in this -- pretty significant delays last time. So we are not really -- I don't think we've really gotten any further behind in that program than where we were when we talked about the first quarter. I mean I think that's been -- I think that's the real difference. We are --.

Then from an inventory standpoint, Mack, you showed that you have 408 low-risk locations. How many of those are located in East Texas or what is kind of the geographical spread of those?

It's throughout East Texas and Western Louisiana, Northern Louisiana and about 80 to 90% of those are concentrated in our East Texas fields. We've got additional down spacing that we haven't even entered into consideration for these numbers.

Are you solely targeting the Cotton Valley out in those plays, Mack? Are you -- there is also some [Travis Peak] opportunity?

Yes, primarily that's correct. Primarily it's a Cotton Valley play but you are absolutely right. There's a significant Hosston potential in Western Louisiana. Travis Peak. We've got [Piloxi] and [Petit] potential in a number of these fields.

So it's primarily Cotton Valley play obviously but we also have the upside of those additional reservoirs.

Are you still thinking 1.2, 1.4 [BEs UR] ?

Yes.

Lastly on Laurel, can you expand a little bit on what your plans are in Laurel? And what you have seen in the four wells you drilled?

Sure. We are excited about the opportunities that Laurel presents for ComStock. It's a layer cake reservoir field. We are looking at multiple completion opportunities; and each well that we've drilled we are currently testing a number of them and 100 to 200 barrels a day per zone.

We are looking at the possibility of being able to commingle those zones in order to recover, commercially recover at a better rate and that has some real appeal for obvious reasons. We have also leased 3,000 gross acres south of a fields called Soso, which has a lot of attraction for ComStock.

We really couldn't talk to anyone about that in the first quarter conference call because we were currently leasing. We have completed that leasing program and we plan to drill five - minimum, at a minimum five - wells across that acreage that we have leased. We are anticipating shallow gas production to the tune of a million to 1.5 million per day per well. Anywhere from 3/4 of a B to a B 1/2 half per well. We are excited about that opportunity and we have a rig planned to move into that area sometime in late October, early November.

So that is in addition to the Laurel play.

And at Laurel can you refresh my memory in terms of what these wells cost and what your target is?

Depending on how deep we drill. Like if we drill through the [Rodesa] and into the [Hosta] directionally we are spending around $2 million to drill these wells and about 500 to 800,000 to complete. If we drill just for the shallower targets, the shallower reservoirs in order to recover those shallow reserves, we are spending about 1 million, 1.2 million to 1.4 million for the drilling and about 300 to 500K on the completion end.

What kind of reserves between the two plays?

It's extremely variable but the deeper plays we are talking 250 to 500,000 barrels; and on a shallower multiple reservoir targets that we have it's basically the same kind of recoveries.

Thank you very much.

Ray Deacon from BMO Capital Markets.

I guess a question for Mack is, do you have a breakdown of the 408 drilling locations? Kind of ballpark how much of that is East Texas?

Yes I do. I've got it by field and of course that is a dynamic that changes with time. We have it broken down approximately 80% of those wells are in the East Texas fields.

Then I would think South Texas is -- .

Write that down spacing. I mean some is 160, some's 80. We've got a few on 40s that I mean -- it's not like we have gone to 20-acre, 40-acre flat spacing and Mack Good alluded to that earlier. We've just hadn't played that game.

The field rules in Carthage, for example, have gone to 20 acres and we were well aware that that's too tight of a spacing in a number of our fields because we have permeable rock. And it makes no sense to drill in that kind of spacing.

But we have some other areas where that is a distinct possibility.

I think, I mean it sounded like you were talking about the potential of some of the shallower zones. But I just got off Penn Virginia's call and they spent a good bit of time talking about the lower Bozier, the Hanesville, some of these lower Cotton Valley stands. Have you looked at that and the potential for your acreage?

Yes. We feel like we are primarily a Cotton Valley Taylor and above -- the Cotton Valley Taylor is a blanket interwoven within the Cotton Valley section and it's extremely prolific through our acreage. It has areas of better [porosity] and perm as you might suspect. The zones below that - the Bozier, etc. is significantly deeper. And they have not been penetrated by any of our wells.

Got it. Do you have anything in your guidance this year for more wells in the Big Thicket and the AA wells field or is that probably going to be in '07?

'07.

'07. Got it. Maybe just a bigger picture question for Jay. I look at the stock and you are being valued at about $1.95 in MCF and something like 235 in MCF on your proven developed reserves. It looks like despite the production growth and the free cash flow, the market is kind of valuing you as though you are destroying value or something. I was curious what you think about that? Were you worried about someone trying to come in and take you over, I guess, trading at these levels? Or buying back shares maybe? I don't know.

The one thing we did, we are kind of an unusual company with having probably $0.5 billion plus of value in Bois d'Arc; and that is really the question mark. That's why we went over the conference call, we said if we hadn't used equity method of accounting you'd see astronomical growth numbers of both revenues. EBITDEX, production reserves, really every category.

What we try to do is, we've tried to go out and we spent probably two weeks in the month of June marketing overseas and domestically, with two different groups and reception has been real well. I think you still when Bois d'Arc went public right after that. I mean, they went from 80 million a day production down to about 20 million a day; and we are still off by about 7 million even though they have had a successful exploration -- success this year.

I think, again, on onshore -- you do have some accounting that to you as an analyst have to walk through and figure out what kind of growth we've had. We did slip up and we didn't get two rigs that quite frankly a large service company said that we would have in place in first quarter. We've tried to make up for that.

In the short run, I don't worry about the stock price because the market always takes care of it. And if we are so cheap that we need to be bought out, then guess what? I bet somebody buys us out. Or it goes up to where it should be. The world is pretty active in M&A right now. What we've tried not to do is increase our cost structure materially by paying out for maybe probable, possible, and mythical reserves that may or may not be there. You have to have a $7 price deck in perpetuities to get your money back.

We've not done that. Maybe we should have but we elected not to. We kept our almost 300 million availability. We kept our 0.5 billion in registered securities. We kept our growth model in Bois d'Arc. We've added our rigs to East Texas. We've been very aggressive in leasing acreage in certain counties around our core area that you will see in the next quarter or two; and we've got a lot of locations to drill now.

If we are that cheap and there's some crazy money out there, I guess they can send it our way.

[Matt McKeery] from Centennial Asset Management.

Good afternoon. Last answer pretty much covered it. How do you think about - along the same lines - how do you think about that Bois d'Arc asset? You have got a very large publicly traded liquid asset on your balance sheet? Do you think about that in terms of -- or do you monetize some of that. Buy back some of your own stock which is pretty cheap on a CF basis and --?

What we and that did -- that's a really good question. I mean we -- if you go back to the origin of Bois d'Arc -- I mean, Bois d'Arc was a private company run by two men. One is a geologist, one is an engineer and they are excellent at what they do.

We saw them create their well. They didn't go buy a company and fire a lot of people and say, "Wow, look how big I am." What they did is they got big because they were successful at the drill bit. For 20 years they have been successful at the drill bit. We missed the first opportunity of their growth back in 1995. We bought them out in December of '97 because between 95 and 97 the company grew to be worth over $200 million which is what we paid per Bois d'Arc.

We had the exploration agreement program that we entered into with them in January of '98 which is a weird agreement because it's a public company now, advancing dollars to a private company. Really two men and an excellent organization as far as geologists and engineers so they could "start up 'again'.

Well, not only did they start up, they discovered hundreds and hundreds of bcfe of reserves. The program was so successful, what evolved was the IPO. And the basis of going public and ComStock supporting that and really ComStock's reputation - along with Bois d'Arc's performance at the drill bit (indiscernible) IPO; but the basis for going public was for that company to bring to ComStock something that most E&P companies our size don't have.

That is a truly successful exploration investment. Which in-house or something you created that's called another New York Stock Exchange Company; and since that day they have done great at the drill bit.

We had a conference call from 1:00 to 2:00. They have had stellar performance this year. They've hit seven out of nine wells. They've got 16 wells they will drill this year. They have a total of 43 wells in the future that they think will add about two trillion cubic feet of gas reserves or reserves equivalent.

Even if they're half wrong that's a tcfe. I look at it this year and they spent $116 million in the first six months, drilling wells. It hadn't cost ComStock a penny. I mean if they've doubled their reserves this year, it didn't cost us a penny. I mean, we have got a good investment there. I don't think they have blossomed. But I am patient because I've seen them for the last 10 plus years create wealth.

I think you're right. I just wanted to get back to the previous question I don't know that it's clearly not being recognized. It's not your fault but (MULTIPLE SPEAKERS) it is what is.

If you get through this year - let's say you get through the summer months we're going into the summer -- we thought that we would end the summer with maybe 3.7 bcfe reserves in storage. There's a glut and so there's been several corrections to the [ENP] stocks. I know we started the year out at -- Ray Deacon had asked earlier, I mean we started the year out at about $30 and maybe $0.50. Well yesterday we hit 30.77 and his whole group, his whole group is down 4% for the year.

Well, guess what? I mean we are down less than his group. That's not comparing out we trade on a per mcfe basis but that is how we traded on the New York Stock Exchange. And if we are so undervalued which I believe we are, then as an analyst or as a fund manager guess what?

Used to, you could just pick a dot on a map and if we were a [E&B] or company or a service company you could make a profit. Well, you have to work a little bit harder in the days we are in now; and I think for one of those companies that if you work it hard enough and you put the value together for the two pieces, at some point in time they either give us the value or we disappear.

That is kind of how that works; but I don't want to create a company being ComStock that is a weak company. I would rather not do that. So we have taken the attitude "let's see what happens through year-end. Let's say what Bois d'Arc's reserves look like. Let's see after a year and a half of Bois d'Arc being public, what are the pros and cons of ComStock having the ownership in it?"

Then we make a decision. I think we could make a better one.

Thank you. Good work.

(OPERATOR INSTRUCTIONS) Paul [Cho] from [Steadfast].

I actually had more of a channel question basically in terms of a home (indiscernible) pricing you've had the issues getting these rigs in. And I am just wondering if you've seen the rate of increase on pricing starts a slowdown on the rig front and how the availability is on the other services like pressure pumping etc.

Yes the day rates have stabilized on the drilling rigs. As far as the other services are concerned you are absolutely right. It is extremely competitive; but we are very fortunate in that we have alliances with a couple of primary vendors who were involved in our '05 program and they segued into our '06 program. We have also picked up a couple of secondary vendors that are also assisting, to help keep our service schedule.

So we are very fortunate in that regard. We don't have some of the same problems that some of the other companies have. So with the nine rigs - the eight to nine rigs - that we plan to run in East Texas we have the service capacity available to handle that. So we are fortunate in that respect.

The cost structure as far as the pumping side of the business is concerned, it has escalated and continues to escalate. That is unlike the drilling side where they escalated very quickly to the level that they are currently at. The pumping services we found were a little more conservative in their rate of increases and so they continue to escalate the cost of their services. We expect some moderate increase for the remainder of the year.

So more so, on the pressure pumping side than on the rig side.

Yes.

A question for Roland here. On your segment breakout, you done what you have historically done. Just very curious at what point are you going to break out Mississippi? Because if you look at your say, well, just in general for your company if you look at say like oil sales at this point you have this other line that's essentially the majority of your oil sales which is pretty much, I assume, Mississippi. With that be --?

I think we are -- once you kind of see what our future is there, if we want to make a complete separate segment and that is really when we make that decision on how we want to show Mississippi. I think it's just kind of, this year is a good year of evaluating it. We are taking some different -- get involved in some different acreage plays there and if those become a big part of our program next year then we want to highlight it.

If they are not going to be a big part of our program, there is no reason to highlight to break it out separately and spend a lot of time on it. Because I think it is an area that we are going to kind of wait-and-see how it looks for next year's program.

So you are still waiting to see the results of the seismic and you are drilling (indiscernible) for the share?

No, yes, we want to see the type and what percentage of our capital budget is that going to be next year? Is it going to be a major focus or is it just one of the another area like our investments in the San Juan Basin or some areas which we could spent a lot of time on them; but they are not going to drive the numbers.

I think we will know that by the end of this year, if that is going to the an area that drives the numbers in the future or if it is just going to be a minor investment like some of our areas like New Mexico.

You expect to complete the sale of your Kentucky assets, I assume, in the third quarter?

It most likely will be October is what we are expecting to actually close the sale.

Could you just remind us again what the reserves related to that are?

It's about, I think it's just about 14 bcf of reserves. Primarily those were undeveloped; and that is the part of the property that developed reserves I think we got good value for in the sale but the undeveloped reserves is what we really -- that's an area that we probably -- they aren't really worth our investment in it, compared to our other, opportunities.

So that is the part of the reserves that have little value.

So you actually know what your selling price is at this point?

I didn't say -- yes, that is under contract that's why we --

We put that in the press release.

Right. For $7 million. And then that, yes, our carrying and our (MULTIPLE SPEAKERS) Properties is roughly 14 million and that generates that loss. (MULTIPLE SPEAKERS) for this quarter. So we think we have it on the balance sheet, now, at what we're going to close at in October.

We show no further questions at this time.

Marie, thank you and those that were here for the full hour, thanks. And if you have any questions, again, don't wait until the conference call to call us. I mean, you know where to get us. Thanks. Bye.

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