Comstock Resources Inc (CRK) 2005 Q1 法說會逐字稿

[OPERATOR INSTRUCTIONS]

Good morning, ladies and gentlemen. Welcome to the first-quarter financial results conference call. I will now turn the call over to Mr. Jay Allison. Mr. Allison, you may begin.

Yes, ma'am. Thank you, Teresa.

Welcome to Comstock Resources' first-quarter 2005 financial 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 "First-quarter 2005 Results." To change the page from 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 COO.

With this call, I will review our 2005 first-quarter financial and operating results, as well as the results of our 2005 drilling program. We will also discuss Bois d'Arc Energy's recent IPO and our upcoming $192.5 million acquisition of properties from EnSight.

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

Page two on the webcast -- 2005 First-Quarter Highlights.

Strong oil and gas prices contributed to strong financial results in the first quarter of this year. Our revenues reached $69.8 million, and we generated EBITDAX of $55.1 million and operating cashflow of $46.5 million. We also generated a profit of $15.9 million or $0.43 per share.

Our net income included a mark-to-market loss of $3.2 million on our East Texas hedge position that reduced our earnings per share by $0.06.

We are off to a strong start with our drilling program with a 95% success rate, having drilled twenty-one wells with only one dry hole.

We have three major transactions that we worked on during the first quarter that will transform the Company and position it for growth in the future. The $192.5 million EnSight acquisition will add 20 million cubic feet equivalent per day to our production, and add 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.

Last July, we announced we had formed Bois d'Arc together with our long-term exploration partner in the Gulf of Mexico. On May 6, Bois d'Arc priced its initial offering at $13.00 per share and began trading on New York Stock Exchange. We are excited to be the largest stockholder in this Gulf of Mexico exploration company.

Page 3 -- Oil and Gas Sales.

For the first quarter of 2005, our oil and gas sales increased to $69.8 million, which represents a 15% increase from 2004's first quarter oil and gas sales of $60.8 million.

Page 4, EBITDAX.

Our earnings before interest, taxes, depreciation, amortization, and expiration expense and other non-cash expenses, increased 19% in the first quarter of 2005 to $55.1 million, as compared to $46.3 million in the first quarter of 2004.

Cash flow -- Our cash flow from operations increased 24% in the first quarter of 2005 to $46.5 million as compared to cashflow of $37.5 million for 2004's first quarter.

Earnings -- Page 6.

In the first quarter of 2005, we reported net income of $15.9 million or $0.43 per share as compared to an almost break-even income of $25,000 for the first quarter of 2004. Adjusting for the mark-to-market unrealized loss on our hedges, we would have earned $18 million or $0.48 per share this quarter. This would have compared to $12.6 million or $0.35 per share in the first quarter of 2004 if you exclude the loss on early retirement on our 11.25% bonds.

Page 7 -- Average Oil Price.

Our average oil price increased 37% in the first quarter of 2005 to $47.68 per barrel as compared to $34.69 per barrel in the first quarter of 2004.

Page 8 -- Average Gas Price.

Our average gas price increased 11% in the first quarter of 2005 to $6.28 per Mcf compared to $5.65 per Mcf in the first quarter of 2004.

Page 9 -- Costs per Mcfe.

Our lifting cost per Mcfe produced increased $0.06 in the first quarter of 2005 to $1.24 as compared to $1.18 in first part of 2004.

Our G & A per Mcfe excluding stock-based compensation, increased $0.05 in the first quarter of 2005 to $0.22, as compared to $0.17 in 2004's first quarter.

Our depreciation, depletion, and amortization per Mcfe produced increased $0.17 in the first quarter of 2005 to $1.62 per Mcfe, as compared to $1.45 per Mcfe in 2004's first quarter.

Page 10 -- Cash Margin per Mcfe.

With the stronger oil and gas prices, our cash margin on a per unit basis improved by 18% in the first quarter of 2005 to $5.10, as compared to 2004's first-quarter cash margin of $4.32.

Page 11 -- Average Daily Production.

Production in the first quarter of 2005 averaged 118 million cubic feet equivalent per day, which is the same as our daily production level in 2004's first quarter and up from our fourth quarter production of 113 million cubic feet equivalent per year. Bois d'Arc Energy's production averaged 41 million cubic feet equivalent per day, our East Texas/ North Louisiana region averaged 30 million cubic feet equivalent per day, our SouthEast Texas averaged 23 million cubic feet equivalent per day, and our South Texas and others region averaged 24 million per cubic feet equivalent per day during the first quarter of 2005. Production gains from Bois d'Arc Energy were partially offset by lower production in our Southeast Texas region.

Page 12 -- Capital Expenditures.

We spent $46.2 million on our drilling program in the first quarter of this year as compared to $38 million in 2004's first quarter. In 2005, we drilled twenty-one wells. Twenty of the twenty-one wells drilled this year were successful with only one dry hole. We spent $29.9 million to drill seventeen developmental wells, all of which were successful. We spent an additional $9.1 million for work orders and recompletions, offshore production facilities, and other development costs.

We spent $16.2 million on our exploration program. $15.7 million was spent to drill five exploratory wells, four of which were successful. $500,000 was spent to acquire exploratory acreage.

We spent $24 million on our onshore properties as compared to $8 million in 2004's first quarter. $12 million was spent on our East Texas drilling program with $7 million in the Big Sandy well and the balance of $5 million in South Texas on our other regions.

Our share of Bois d'Arc's expenditures was $22 million as compared to the $30 million we spent on our Gulf of Mexico properties last year.

Page 13, Our Properties.

East Texas/North Louisiana region --

Production averaged 30 million cubic feet equivalent per day in this region in the first quarter of 2005, which is the same as 2004's first-quarter production rate. We expect production to increase significantly starting in the second quarter as a result of the EnSight acquisition and the East Texas drilling program.

We drilled nine successful wells or 6.8 net to us in this region in the first quarter. The wells drilled have an average production rate of 2.4 million cubic feet equivalent per day per well. We are currently operating four rigs in this region and plan to drill another sixty wells by the end of the year.

Page 14 -- Our Southeast Texas Region.

Our production averaged 23 million cubic feet equivalent per day in 2005's first quarter in this region, which decreased around 25% from production in 2004's first quarter.

Production has declined in this region partly due to a three-day shut-in of the plant that processes our gas, and due also to expected production declines from the field. We hope to turn the decline around when we drill two development wells on the Indian reservation later this year. As soon as our settlement is approved by the Federal Government, we will drill these wells.

We are currently drilling the Blackstone Mineral Company unit B, number 1 wells to test the Big Sandy prospect to the South of the Double A Wells field. This exploratory well is currently drilling at 14,000 feet with the objective of testing a highly prospective lower Woodbine reservoir target at a depth of approximately 18,000 feet. The upper Woodbine target that we were also testing does not appear to be productive.

As result of several problems and difficulties encountered during drilling operations, we expect an average total depth on this well in June of 2005, at a total estimated cost of approximately $12 million. We own 100% of this well.

Page 15, South Texas/Other Regions area.

Our production averaged 24 million cubic feet equivalent per day in 2005's first quarter and our South Texas and other regions, which is up approximately 23% from production in this region in 2004's first quarter. We drilled five wells in our South Texas and our other regions in the first quarter of 2005. Four of these wells were successful and one was a dry hole.

Two of the successful wells have been tested at a per well, average rate of 2.3 million cubic feet equivalent per day. The remaining two are in the process of being completed.

Page 16 -- Bois d'Arc Ownership.

On May 6, Bois d'Arc Energy priced its initial public offering of its common stock. Bois d'Arc Energy plans to repay the $158 million currently outstanding on the credit facility that we provided in connection with the formation of Bois d'Arc Energy in connection with the closing of the offering.

After the offering closes, we will own 29,935,761 shares of common stock of Bois d'Arc Energy, which will represent 48.3% of the basic shares that Bois d'Arc Energy will have outstanding. If the underwriters exercise the entire over-allotment option, our ownership of the basic shares outstanding will be reduced to 46.9%.

We have proportionally accounted for our share of Bois d'Arc's operations since its formation in July 2004. Now that Bois d'Arc is a public company and our ownership is less than 50%, we will account for our investment in Bois d'Arc under the equity methods starting in May of 2005.

Page 17 -- Bois d'Arc Energy.

Our share of Bois d'Arc's production averaged 41 million cubic feet equivalent per feet a day in the first quarter, this was up 10 million cubic feet equivalent per day for the fourth-quarter production rate, which is impacted by hurricane Ivan.

Bois d'Arc Energy has had excellent results in its drilling program so far this year. They have drilled eight successful offshore wells and have had no dry holes.

Bois d'Arc Energy's eight successes include four development wells and four exploratory wells. The reserves added as a result of these eight successful wells are expected to more than replace Bois d'Arc's 2005 estimated annual production. The larger discoveries were Ship Shoal's block 92 and 111 and South Pelto 5.

Two successful well to Ship Shoal 92 proved up the Paddlefish Prospect, and discovery well drill at Ship Shoals 111 proved up the Laker Prospect. A 15,700-foot-deep exploratory well drilled at Southbelt 05 was successful.

Page 18, EnSight Acquisition.

We announced on April 10 that we are purchasing certain oil and gas properties from EnSight Energy Partners, which is based in Shreveport, Louisiana. We have entered into a purchase-and-sell agreement with EnSight to purchase their oil and gas properties in Texas, Louisiana, and Mississippi , and expect to close the acquisition on May 12. The purchase price is $192.5 million with an effective date of April 1, 2005. The properties that we are purchasing include 240 active wells, which are currently producing 20 million cubic feet equivalent per day.

In addition, we have identified 424 potential drilling locations on these properties, which will give us the opportunity to create substantial value from this transaction beyond the proved reserves being acquired. We are acquiring interest in 45 separate fields and will operate 18 of these fields. Many of the properties are in our large -- largest -- core operating region in East Texas/North Louisiana.

The acquisition also includes four oil fields in Southeast Mississippi. Of the 240 wells acquired, we will operate 91 of them, including 12 already operated by Comstock.

The acquisition includes 53,000 gross acres, and 22,000 net acres, which is approximately 50% held by current production. The purchase price we are paying represents $1.60 per MCFE based only on the proved reserves being acquired and not giving any value to probable and possible reserves that we have identified.

Page 19, The EnSight Reserve Profile.

We estimate that the acquisition has proved reserves of 120 Bcfe. 57% of the reserves were 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 required and 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 20 -- Capitalization.

At the end of the first quarter, we had $429 million in debt and $381 million in book equity. Our debt-to-total book capitalization was at 53%.

In May, we will close $192.5 million acquisition of properties from EnSight for which we have already paid a $9.7 million deposit. In early April, we sold 4.5 million shares of common stock in an underwritten public offering for net proceeds of $121 million to help finance the acquisition.

The initial public offering of Bois d'Arc Energy is expected to close on May 11, which will repay the loan we made to Bois d'Arc in connection with it's formation of $158 million.

Pro forma for the EnSight acquisition, the common stock offering, and the Bois d'Arc Energy refinancing, our total debt would decrease to $333 million, and our equity would increase to $502 million. As a result, our debt to book capitalization ratio improves to 40%.

Page 21 -- 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 very predictable increase and our onshore production levels this year. In combination with the EnSight acquisition, our onshore production should increase by 20% to 25% this year over 2004.

The EnSight acquisition adds 424 drill sites to our onshore drilling inventory. When combined with our 200 drill sites that we have on our properties, we will be able to expand our onshore drilling program to support our growth in 2006 and future years. With the common stock offering and the repayment of our loan from Bois d'Arc, our debt will fall to 40% of our total capitalization, giving us a strong balance sheet to support future growth.

We also expect that Bois d'Arc will have an outstanding year growing it's reserve base. To date, in 2005, Bois d'Arc is 8 for 8 in it's drilling program, and it has already more than replaced it's expected 2005 production of around 30 Bcfe.

With that, Teresa, I would open it up for questions.

Thank you. At this time, we will now begin the question-and-answer section. [OPERATOR INSTRUCTIONS] At this time, we do have Wayne Andrews with Raymond James. Please state your question.

Thank you. morning, Jay, Roland, Mack. sounds like you are off to a great start operationally.

I haD a couple of questions regarding a couple of wells that you did mention. First, Jay, you talked about your Big Sandy prospect and the -- you mentioned an upper Woodbine zone. Could you give us some more detail on that, and how that relates to the unexpected gas that you hit on the first side -- the first test of that?

I want to have Mack go over the Big Sandy, Wayne, if that's okay?

That's perfect.

Wayne, this is Mack.

The upper Woodbine was logged and found to be absent in pay. The abnormally pressured interval that caused the drilling problems was above the upper Woodbine. It was totally unexpected. We think it was a stray, thin, sand, highly pressured, of course, that resulted in the stuck drill pipe. The logs that we ran did not indicate it was pay. The subsequent operations after logging the upper Woodbine involved an effort to set a drilling liner through the upper Woodbine, so that we could drill to the lower Woodbine prospective target.

To talk a little more in detail about the lower Woodbine -- it is a highly prospected target, and it is set up by well about a mile to the Northeast that produced approximately 6/10 of a Bcf from the lower Woodbine. It did not complete all the pay in the well. It was not simulated. And we think it is on the edge, at least that's our hope -- that the Big Sandy well will penetrate a thicker-Woodbine -- a lower-Woodbine development than found in this offset well that's a key well for setting up the lower Woodbine prospect.

When we tried to set the liner through the upper-Woodbine, the liner failed. We subsequently got some drill pipes stuck in the hole. We are currently sidetracking around that fish to the lower-Woodbine target, and we expect to hit the lower-Woodbine and to be able to log it in the first week or so, of June.

Great. That lower Woodbine is your original objective in the well bore?

We had two objectives. Obviously, the upper Woodbine didn't work, and the lower-Woodbine was the least risky, in our opinion, prospect target, just because it's obviously set up by that offset well.

Great.

And then maybe can you give us a little bit of comment on the South Pelto 5 well that you also discussed and said it might be -- you expect production here in the second quarter and maybe any kind of -- any idea on rates? It sounds like a pretty good discovery at over 100 feet of net pay.

What we did -- we just finished the --

That well was just actually a re-entry of an existing well that -- well bore -- that was at South Pelto 5 into this deeper zone, and it looks like a very good discovery. We haven't tested it yet, Wayne, to really know what type of production rate we can expect out of it. But I think it is a -- it's a well -- it is somewhere around a 10bcf-type well.

And should be pretty easy to hook up considering it was already in your existing infrastructure, correct?

Actually it is kind of hooked up through that old well bore.

Yeah, it -- I think the time frame is a 30-day time frame or less to be connected to sales.

Great. And thanks.

And on your onshore production, you are off to a good start in -- in your North Louisiana and East Texas area. Any idea how -- can you give us any guidance on where you expect volumes to go from that region during the course of the year?

Yeah why don't I -- before we give you a straight answer than that -- I am going to let Mack go over what he is doing with the number of rigs and how many wells -- the program. If that's okay, Wayne?

That's perfect.

We have three rigs currently running and a fourth rig moving in to rig up, should spud in another two weeks. And we have a fifth rig that we'll be moving in in about three weeks. So, obviously, ramping the program up from the original three-rig operation.

The lag that we are having in getting production into sales is caused by the backlog on the completions. We were currently completing six wells. We have -- obviously -- services already scheduled for those FRAC's of getting the wells completed. We are finding in East Texas, there is some line pack occurring from just a lot of production -- flush production -- coming from a lot of operators who are active in the East Texas play.

But the ramp-up in the second, third, and fourth quarter, we expect to be able to add about 5 to 8 million net per day. That's our goal. And then, the EnSight package is really going to be an interesting challenge for us because we're -- moving -- trying to move in -- a couple of rigs there to start our East Texas program in the EnSight acquisition.

Do you think that should be one of your bigger growth areas -- obviously onshore -- with that level of activity?

No question, Wayne.

We are excited about the opportunity that not only we have with the existing asset package in East Texas, but the Ensight addition gives us several fields -- actually six fields in East Texas -- and we get 10 fields operated -- fields in Louisiana -- to target for additional drilling, and then, of course, we have the Mississippi fields that have significant development as well. So we are excited about the opportunity to create value there.

Great, thanks, gentlemen. I will let some others ask questions.

Wayne, one other thing. I think -- and Mack -- I think the majority of reserves as far as the big upside from Big Sandy, was the lower-Woodbine.

That's exactly what I expected.

Thank you.

Thank you. At this time, we do have Van Levy with CIBC. Please ask your question.

Good morning, guys, how are you?

Hi, Van.

Can you, Jay, give us a sense of what the Hammon is doing right now? That was a pretty big well, wasn't it?

Yes, the Hammon 2 -- the Hammon 1.

The Hammon 1. It is currently doing about 5 million to 6 million a day.

Remember, we had choked that one back to 19.

Right.

And just following up on Wayne's comment. The lower Woodbine -- can you give us a sense of reserve potential, and could you clarify what the name of the analog well was?

The Cody number one was the offset, and the reserve potential varies anywhere from 20 to 80 Bcfe, depending on how you want to map it. It could be significantly greater than that depending on how far to the South the lower-Woodbine extends.

We have a well to the South -- about a mile and a half distant -- the ARKOFE (ph) that had Woodbine pay and had a mechanical failure. Depending on how thick the lower-Woodbine pay sands are that we encounter with Big Sandy and how far that extends to the South and North, Northeast to where the Kirby is, will really tell the tale as far as reserves.

Give us a sense of -- when you say "thickness" -- what would be right in the fair way of thickness, what would be thin, what would be thicker?

Well, you know, we have had internal conversations anywhere from 20 to 100 feet of Woodbine -- lower-Woodbine pay with processes approaching 15% to 17%. And that's what we are hoping to encounter with Big Sandy, something on that order of magnitude.

Okay.

And then the Robin prospect -- What is the timing on that?

We're pursuing a big thicket permit that would allow us to drill a -- from a surface location within the park boundaries, and really the timing is dependent upon getting approval for that permit. Our target is some time next year for Robin.

Van, what Mack said is on the well we are drilling right now -- Big Sandy -- if it had been a vertical well, we probably wouldn't have had the drilling problems.

Right.

And $12 million, we've probably spent 7.

Right. .

Since you are drilling directionally, you have those problems. The same would go for the Robin. If we can get a location where we can drill a vertical well, that's what he wants to do. You can still drill a directional well, but we are have to wait and see what happens with the Big Sandy in order to decide if that risk is worth another, you know, $6 million or $7 million.

The drilling risk is significantly less than the vertical home.

Okay. I have a question.

Now that you have the Bois d'Arc done, will you -- and you are going to use the equity method -- are you going to restate your financials to reflect that, or will you just kind of tag on in the third quarter using the equity method?

There's been -- a restatement wouldn't be appropriate because of the equity method wouldn't have been available with the higher ownership. But we will provide some breakout numbers in our releases, but we will basically begin to use the equity method in May, even the month of April will still be under the proportional consolidation.

So your Gulf of Mexico production will go away under your new booking, so it will look like you will be a decline in production on a corporate basis. Is that a fact or not?

It is obviously there, but --

Right. So you will not, on a corporate basis, be able to restate -- to show just the onshore?

No, there would be no basis for a restatement. because you couldn't use that accounting --

Okay.

-- for the prior periods.

I think you would just have to break it out with supplementary information or showing the components that make up the -- we will still be recording our share of Bois d'Arc's Energy's income. It just --

No, I understand.

It is separately.

East -- East Texas, can you give us a sense of economics, drilling economics at today's prices -- $6, $7 prices, and then where they fall off on the rate-of-return basis? What is the lower limit when you get maybe a 10% rate-of -return or something like that?

We didn't go down to the 10% level. We are looking at -- the target for the program is to generate at a minimum a 20% risk rate-of-return. That's our hurdle internally.

Right.

And we -- we've looked at what combination of gas price versus drilling and completion costs would -- would, under a variety of scenarios on performance, present that kind of rate-of-return. And so it's -- it's a case-by-case basis, but I can tell you this, as a total program, so far, we are exceeding to a very great extent that 20% rate-of-return hurdle.

I would think so.

You might go over, Mack, the drilling days that you are trying to --

One of the things that when we first got into this program that was a goal, and it is a goal that we were getting better at on a field-by-field basis in achieving, and that is reducing the number of drilling days necessary to TD wells. And, of course, time is money, and with the rig rates and services and being able to get wells to sales as a result of drilling the wells faster, getting them to sales faster, we've taken our average drill time curve from 26 days down to about 17 days. And we've actually drilled three different wells to a depth -- total depth of 10.2 to 10.4 -- 10,400 feet -- in less than twelve days.

Wow.

So we are very happy about that. We've got -- starting to develop a program that is yielding results, and that's why we are able to -- we feel pretty confident in being able to drill the number of wells that we've indicated that we planned to drill with the number of rigs that we have currently.

Okay. Last question. Laurel -- can you give us an update there, and where you are starting the exploration activity there?

Exploration probably won't take place this year. The first thing we are going to do is really firm up the water flood studies that have been conducted in the past. We have a number of recompletion -- very excellent recompletion -- opportunities in Laurel. Production right now is north of 2,400 barrels of oil per day. We're currently, with EnSight, participating in -- or soon -- will operate a couple of recompletion projects that are going forward. So Laurel is an excellent opportunity to add value, and developmental drilling this year will include at least two wells that we feel will allow us to optimize the water flood operation there.

Great. Okay, thanks.

Sure.

Thanks, Van.

At this time, we have Ron Mills with Johnson Rice. Please state your question.

Good morning.

Just to follow-up on a couple of the questions -- the South Pelto 5, based on the description, that is not the Steelhead prospect, is that correct?

That's correct, it is not. That's a different property.

Still --

Still adds a extension of some of the Laker discoveries.

So, Steelhead, then, is in the Ship Shoals area?

Yeah, 111. South Pelto 5 is one of the largest producing fields, and it is a field that has made discoveries in the past, and this was simply a follow-up -- a follow-up at deeper target that they wanted to drill. They used as existing well bore to be able to do that at a very low cost.

The Steelhead, Ron, is about a 40 Bcfe-type prospect.

That will be drilled later this year.

Okay. That hasn't been spotted yet?

That's right.

Okay.

Since we are going to the equity method, can you provide a little production guidance in -- you did from a production standpoint, 20% to 25% growth this year -- from a cost standpoint, how the onshore costs look relative to your proportionately consolidated costs of the past?

Sure.

Basically, if you are looking at onshore production, we averaged about -- about 81 million a day last year on the onshore part of the Company. That's the base you are comparing to, I guess, to measure that production growth. If you are looking at the cost structure, we think that the -- the actual lifting cost will look pretty similar to the consolidated numbers in about the mid-$1.20 range on a go-forward basis.

How about from a DD & A standpoint? And how much of your -- in terms of G&A -- are you -- should G&A change significantly?

We no longer pick up -- we won't be showing that our share of Bois d'Arc Energy's G&A, which I think is running about 1.2 million a quarter. So that -- you'll see that part of it will be reduced by 1.2 million a quarter.

And on the DD & A rate?

The DD & A rate would be more like $1.50 as compared to $1.60 -type rate we had in the first quarter -- a little lower.

Okay.

It already incorporates in -- the $1.50 incorporates in the EnSight properties and what we are expecting from those.

Okay.

And then from -- just the accounting mechanics, I am assuming you just have -- in your income statement, you will have an income from Bois d'Arc, but that -- and so you will no longer report the production. Will you book your proportion of the Bois d'Arc reserves?

Right. We actually will, but we will show those separately in a separate disclosure. We will show the reserves from an equity investee separately, so you can see how it breaks out.

From a cashflow standpoint, you show the income from Bois d'Arc on your income statement, but because you are just holding the 46 -- 47 -- or 48% of the shares. You don't actually report those cashflows -- ?

That's correct.

Or EBITDA's for the quarter, correct?

Correct.

Would you only pick up those in cashflow to the extent they are paying dividends. So you would not -- our share income of Bois d'Arc's income will not be in our cashflow from operations numbers, nor would our share of their capital expenditures or other cash items.

Okay.

And finally, to follow-up on Van's question or just to ask it a little bit differently, in East Texas, Mack, can you walk through what your expectations were to get to those rates of returns in terms of expected costs per well, and expected IT, and expected reserve potential?

Sure, 172 Bcf per well on the reserves. These are gross numbers. $1.4 million per well drilling complete. IP's of 1.35 million per day.

But your most recent wells have come on at higher IP's?

Correct.

And has -- should that -- I mean, theoretically, I guess that should impact the reserves from those wells, correct?

That's correct.

And, are you -- is that impact from the 1.352 million a day -- is that tweaking your FRAC techniques or your completion techniques, or do you think you just hit a little bit more of a sweet spot on some recent wells?

All of the above, and not to be too cute here, we've put a lot of effort inhouse to developing the correlation work and the modeling work to allow us to identify and quickly set up the completion procedures for the most prospective sands, the highest potential completion intervals in the wells that we've recently drilled. This is really starting to pay dividends for us.

We are also interacting on an almost day-to-day basis with service company personnel to -- as you say -- tweak the FRAC design. We, in prior years' past, went with a fairly standard approach to how we completed the wells, and now we're evaluating the completion of procedure, if you will, on a well-by-well basis, and it is really starting to pay off in the performance.

Are those numbers that we are talking about, are those Cotton Valley only, or do they include potential Travis Peak or Hoston?

Right now it's Cotton Valley, but we have some wells that we plan to drill later this year in section that will target the Hoston and Travis Peak.

Alright. Thank you very much.

At this time, we have Brad Beago with Credit Lyonnais.

Good morning, guys.

Hello.

Several of my questions have been answered, but just kind of strategically for you, Jay, you've got a very large drilling inventory -- probably larger than you have ever had in the Company's history. During the remainder of this year and going into next, are you continue to actively look at acquisitions, or do you think that the best course of action is just to work as hard as you can to draw up this inventory?

Well, I think if you go back to -- first of all Bois d'Arc. That has been lingering around for a year, and we priced that on Thursday. I think that -- that's a big event for the Company. And I think, you know, in the interim -- of course, we looked at anywhere from 4 to $5 billion for the possible purchases every year. We probably look at 200 different deals, and every now and then, we buy something. I know EnSight kind of popped up -- what we would call corporately -- at a bad time, but usually, good things happen in times when they stress you out a little bit. So we did acquire that, and as Mack said this morning to me, he said, "the more I look into it, the more excited I get about it." We do have a little over 400 drill sites there, and I know EnSight had two rigs under contract, and we are trying to keep those two rigs as Mack alluded to this morning.

I think our business plan is this -- we will probably put a new Shell registration this place in summer just to have one in place for $0.5 billion dollars because we had one in place for $300 million. We used part of that for the bonds to reduce our interest expense from 11.25 to six and seven-eighths, and then we used are the remaining part to partially pay for the EnSight acquisition. I think we will put that in place this summer.

I think our corporate goal is to operate what we have. We are going to produce -- we are going to replace probably almost two and a half times what we will produce this year just through EnSight. I think Mack has got a good group of people, and he's working them hard now. I think you can overload a company, although we have pushed a lot of the operations over to the Bois d'Arc side now, and that's completely a separate entity.

The good part of what we are doing now, Brad, is that where Mack was spending half his time offshore and half onshore, he has that luxury of really ramping up onshore. And then, we are going to keep these four, five, six rigs busy. We will continue to look for something to buy. I doubt that we buy anything, period. That is not our corporate goal.

Our corporate goal is to materially increase production in the East Texas, South Louisiana area. At the same time, drill the two wells in Double A because we are near a settlement with the Indians for the first time in about three or four years.

Hopefully, we will make a well at Big Sandy. If we don't, we will have a $12 million dry hole. If we make a well, then we are going to add some meaningful reserves there. If we don't make one, we are going to drill another one.

I remember our first well in the sunflower field was a dry hole. That was a [inaudible] feed well, and it was a dry hole. We owned 100% of it. We waited two more years and we hit the Hammon 1. So, we just take that in stride.

But now, I think our goal -- and we can have the single best year we have ever had -- we are set up to have right now by reducing our debt-to-cap, having the least cost for the rate on our debt, and have the most production we have ever had. So I think our focus is just -- really to push Mack to build as many wells prudently as we can drill, and to try to hit this 1.4 million to drill and complete in the East Texas well, and then have a well. Our wells have been coming in a little over 2 million a day versus just 1.35, and we have not factored that into our numbers. The reserves probably are a little over 1.2 Bcfe that we have hit. So I think -- I think that's what we are focused on. Anything that we do over and above that would just be an opportunity that we couldn't say no to, but I don't really see that happening.

Okay. That's good color, Jay.

I guess -- maybe one or two questions back on -- back on Double A. What would the implications be for the Robin prospect if the Big Sandy does not find pay in the deeper-Woodbine?

I don't think there is any question that it changes the risk profile if the lower -Woodbine is absent in Big Sandy. We would have to reassess the risk profile for Robin, but Robin is some distance away from Big Sandy, and the depositional model is still in place well to the South of Big Sandy, but -- you are certainly correct in asking the question, what impact does it have? And we would have to re-evaluate the Robin well in terms of risk.

Yes, because, Brad, if you look at our seismic, I even in, the TD of this lower-Woodbine well should be in the middle of that reservoir that we are looking for. It shows up in a Kirby well. So if we didn't have any pay in it, then, we would have to re-assess all of our seismic because there is an interpretation that's wrong. If you only have half the amount of pay you are looking for, then you still have to reprocess it all and look at it again.

One thing to quickly add to what Jay said -- he remarked earlier about the Vastarfee (ph) being the precursor well to the Hammon 1 -- when we drilled the Vastaree (ph) as a dry hole, it was an economic failure, but a technical success in that it gave us additional information to evaluate and to reassess our go-forward plan for exploring in the area. Of course, you don't know until you get the data, what the data is going to tell you. That's obvious. But, just to point out that the Big Sandy dry hole event -- if it is a dry hole -- and there is no pay in the lower-Woodbine, it certainly doesn't condemn Robin. It gives us additional information to evaluate and reassess what we want to do and where we want to do it.

I think my attitude on the Big Sandy is I thought we would have multiple-pay sand. I thought we would have an upper-Woodbine as kind of the fall back pegs. Our goal was to drill the lower-Woodbine. We will the drilling problems. There, for a while, we didn't know if we could deepen the well to hit the lower-Woodbine, fortunately we can.

We don't have any bailouts. We have to hit the lower-Woodbine and make a big well or it's a dry hole. That is the only scary part of it, but that's where the big reserves were to start with, and that's why we wanted to drill it. So nothing has changed there. Just a little comfort factor is gone that you don't have an upper-Woodbine as a bailout.

All right. Great. Thanks, guys.

Thank you.

Thank you, at this time, we do have Ray Deacon with Harris Nesbitt. State your question.

Hey, Mack. I was asking to go you how many locations would you have if you do work out an agreement with the tribes -- was it seven? Am I remembering that right?

We have five firmed up, and then, I believe there are three others that are contingent.

Okay.

And an agreement has been worked out, it's just getting it approved.

The Indians have signed this, Ray, and so have we, and so has the other exploration company, and there's a thirty-day, forty-five day time period to have governmental approval. I think we're at that or beyond that. Mack, is there an update on that?

I just know what's eminent.

We think that is going to happen this year for certain because everybody's signed off on it. There's not any additional provisions to negotiate.

Okay.

Net reserves typically have been 4 to 8 B's on average -- does that sound about right in the Double A Wells?

Yes, I think that is the target reserves for those wells on the reservation. Yes, sir.

Okay. Great.

And just one last question -- it seemed like if you added up all the wells at Bois d'Arc that could come on by year end, you are might be pushing 100 million equivalence a day by the end of the year, just 50 at the beginning. These last two wells that have worked -- does that change picture there? Is it better than that?

What we said in the fourth quarter, Bois d'Arc had 52 million a day production because of hurricane Ivan. March, Ray, was at $70 million, and the exit rate is projected $100 million a day. There are about 20 wells, all but about three or four of those, are ready to be connected in the next several quarters. We feel pretty comfortable at about $100 million exit rate.

I think these wells in the first quarter have really firmed up, you really, probably, need to drill two more wells to make that forecast and then everything is just up to timing.

Okay.

Timing and connection. But --

Great.

And a really excellent first quarter.

Right. And if you look at East Texas, is there -- you know -- is it still fairly difficult to get rigs? What do you have lined up? How many rigs are there now, and where do you think you will be by the end of the year?

We have three working right now. We will be moving in a fourth in a couple of weeks, and in about three weeks, we will have a fifth rig working.

Okay.

The -- the bottlenecks of the program or the governor, as far as being able to ramp up the program, is obviously drilling rig availability. In East Texas, it is 98% utilization rates on drilling rigs. There are no rigs -- if they are not under contract -- there are no rigs available is what I am trying to say, if you don't have them under contract.

Right. Got it.

So what we are doing here at Comstock is keeping -- obviously -- keeping the rigs that we have, and working with other companies to be able to take advantage of drilling rigs that they temporarily can't find a location for, to drill one or two wells for us in the interim.

Got it. Okay. Thanks a lot.

Yes, sir.

Thank you, Ray

At this time, we have Ron Mills with Johnson Rice. Please state your question.

Just to follow on Ray -- the Indian lands -- what did you say those potential reserves were for location?

Between 4 and 8 Bcf.

Okay.

On the EnSight rigs -- EnSight currently had two rigs running. Is the expectation you will be able to maintain those rigs or does the changing control put those rigs basically back out on the open market?

That will be a shared situation between Comstock and EnSight, and we are working with EnSight to take advantage of that rig availability.

Okay.

And then finally, Rowland, in the first quarter, the onshore production was probably a little lighter than I was looking for. Can you point to any one thing that impacted that? Were there were any down times at plants or pipeline issues or anything?

In Double A, we had a plant shut-in for maintenance for three days that impacted the net profile there.

Currently -- I mean this is -- this is a rolling problem throughout the region. We were shut in for two days in East Texas recently due to another plant maintenance issue, and when that happens, gas is redirected to other pipes, which elevates line pressure, which causes back-off issues.

The other thing I want to point out is -- when you shut in wells in a number of our fields or any operators' fields for that matter, it takes a few days to regain stable production from those wells. So it is not just a matter of plant shut-in, it also has an impact on getting wells back to the production level that they were before the shut-in.

And do you know about how much of that impacted the first quarter?

We know that just in Southeast Texas region, it was just about 3 million a day, type production that was off due to that shut-in period, and I think it was a couple million a day in the East Texas region, similar to Gilmer plant -- similar issues there.

Ron, we thought it was about 5 million to 6 million a day.

Okay. That would explain the --

That's where we saw it deviate from our forecast was in those areas.

All right. Thank you all very much.

Thank you.

[OPERATOR INSTRUCTIONS]

Just a couple of housekeeping items. One -- the cash on the balance sheet at the end of the period was $10.6 million. Everybody seems to ask that.

And then, let me break out the lifting cost for all the people that did their models. In the first quarter, 2.1 million was severance and production taxes, 11.1 million was the remaining part of the lease operating expense, for a total of 13.2.

And then, we will update everyone on the Big Sandy when it is evaluated -- since it is such a large project for the Company -- we will put that out in June once we have that evaluated and know what it looks like.

Mack thinks that we will probably start drilling in the lower-Woodbine maybe the first week of June, is that right, Mack?

That's correct.

That is a guess. Any other questions?

Mr. Allison, there are no other questions at this time.

All right, Teresa. Thank you.

Thank you, everyone.

Thank you.

All participants, your conference has now ended.