Comstock Resources Inc (CRK) 2003 Q2 法說會逐字稿

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

Thank you, Monica. Welcome everyone to the conference call. Welcome to Comstock Resources second quarter 2003 financial and operating results conference call. You can view a slide presentation during or after this call by going to our Web site at www.comstockresources.com and clicking "presentations". There you will find a presentation entitled second quarter 2003 results. To change the page of the presentation, click on the arrow on the page. I am Jay Allison, President of Comstock. With me this morning is Roland Burns, our CFO and Mike Taylor, our VP of Corporate Development, who will help answer questions.

With this call I will review our second quarter 2003 and six months ended June 30, 2003 financial results, as well as the results to date of our 2003-drilling program. Our discussions today will include forward-looking statements within the meaning of Securities Laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct.

Page two. Second quarter 2003 highlights. On the call today we will review our second quarter financial results where we generated a net profit of $14 million or 40 cents per share. In the second quarter we continued to improve our balance sheet and we were able to pay our debt to capitalization ratio to 46% from 64% where it was at the end of 2002's second quarter.

The conversion of our preferred stock, which occurred in the second quarter, strengthened our balance sheet and eliminated future dividend payments of $1.6 million per year or $400,000 per quarter. We have had excellent results in our drilling program with 21 successes out of 23 wells drilled in the first half giving us a 91% success rate. Six wells that were drilled are still being tested. With the drilling successes that we have had, we have 25- to 30-million cubic feet a day equivalent of gas production, new production available to come on line when new production facilities are completed. These new wells should be put on line within the next three quarters.

Page three, oil and gas sales. Strong crude and natural gas prices allowed us to realize sizable increases in our oil and gas sales for the second quarter and first half of 2003. Our second quarter sales of $57.2 million were up 50% as compared to last year's second quarter sales of $38 million. For the first half of this year, our sales totalled $125.7 million, an increase of 95% over sales in the first half of last year, at $64.5 million.

Page four. Earnings before interest, taxes, depreciation, amortization and expiration expense or EBITDAX increased 57% in the second quarter to $44.8 million as compared to $28.5 million in the second quarter of 2002. EBITDAX in the first half of this year grew 117% to $100.5 million as compared to $46.4 million in the first half of 2002.

Cash flow -- Operating cash flow. Our cash flow from operations increased 77% in the second quarter of this year to $37.4 million from $21.1 million in the second quarter of 2002. Operating cash flow for the first half of this year was $85.3 million, up from cash flow of $32.4 million for the same period last year.

Earnings -- We reported a net profit of $14 million as compared to $3.2 million for the second quarter of 2002. For the first half of this year, we had net income of $34.1 million as compared to a net loss of $1.5 million for the first half of 2002. We had 40 cents in earnings per share in the second quarter as compared to 11 cents in 2002's second quarter. For the first half of this year, our earnings per share were $1 as compared to our loss of five cents per share for the first half of 2002.

Production -- page seven. Production in the second quarter averaged 118 million cubic feet equivalent per day, which represents a 2% increase from 2002's second quarter production level of 116 million cubic feet equivalent per day. We averaged 42 million cubic feet equivalent per day in the Gulf of Mexico region, 32 million per day in Southeast Texas, 31 million per day in East Texas North Louisiana and 13 million per day in South Texas and other regions during the second quarter. Production was down slightly from the first quarter but should be up in the third quarter, which is expected to average between 125- and 128-million cubic feet equivalent per day.

Average oil prices -- page eight. Our average oil price realizations were up in 2003 as compared to the same period last year. For the second quarter of 2003, our realized crude oil price increased 16% to $28.83 from $24.96 for the second quarter of 2002. For the first six months of this year, our average oil price increased 38% to $31.39 as compared to $22.80 for the same period in 2002.

Average gas price -- Gas prices have increased significantly in 2003 over last year. Our average realized gas price in the second quarter was $5.44, 57% higher than our second quarter 2002 average of $3.47. For the first half of this year, our gas price averaged $5.98, which is 104% higher than our average price of $2.93 from the first half of last year.

Cost per Mcfe -- Cost per unit of production second quarter, page ten. Our lifting cost per Mcfe increased by 18 cents in the second quarter to 98 cents from 80 cents in 2003. The increase is attributable to higher production taxes related to increased oil and gas prices. Our G&A expense per Mcfe increased to 32 cents from the second quarter from 10 cents in the second quarter of 2003. The increase is attributable to increased personnel costs as we have recently expanded our technical staff, including opening a Houston office this year. Depreciation, inflation and amortization for Mcfe produced has increased by five cents to a $1.35 in the second quarter of 2003 as compared to a $1.30 for the same period in 2002. The increase is attributable to higher production rates and a higher average amortization rate of our properties. Cost per Mcfe, six months ended June 30. Lifting costs per Mcfe produced increased by 21 cents for the six months ended June 30 from 80 cents in 2002 to a $1.01, due to the higher oil and gas prices. Our G&A expense per Mcfe increased to 23 cents in the first half of 2003 from 10 cents for the same period in 2002. Depreciation, depletion, and amortization per Mcfe produced has increased by 6 cents in the first half of 2003 to a $1.35 from $1.29 for the same period in 2002, due to higher average amortization rates of our properties.

Cash margin per Mcfe -- Page 12. Due to higher oil and gas prices our cash margin per unit of production increased 48% in the second quarter of 2003 to $4.01 per Mcfe as compared to $2.70 in 2002's second quarter. Our cash margin for the first half of 2003 grew 107% to $4.57 per Mcfe as compared to $2.21 per Mcfe for the same period last year.

Capitalization -- Looking at our balance sheet, page 13. At the end of the second quarter, we had $336 million in total debt, $116 million was outstanding under our bank facility which has a $260 million borrowing base, giving us $144 million available under the credit facility. The balance are a 11.25% bonds which are callable in May of 2004. During the second quarter, the holders of our preferred stock converted their preferred shares into 4.7 million shares of our common stock. This conversion reduced our annual preferred stock dividend requirement by $1.6 million, and increased our common stockholders' equity by $17 million. Debt as a percent of our total book capitalization has fallen from 64% at the end of 2002's second quarter to 56% at the end of 2003's second quarter. We paid down another $13 million of debt in the month of July. To date, we have reduced our debt by $43 million this year and we expect to continue paying down debt throughout the rest of the year.

Page 14, capital expenditures. In the first half of this year, we spent $39.2 million on our drilling program as compared to $36.1 million in the first half of 2002. We spent $8.4 million to drill 13 developmental wells, all of which were successful, all are still being evaluated. We spent an additional $6.4 million for work overs and completions, offshore production facilities and other development costs. We spent $24.4 million on our exploration program, $21.2 million was spent to drill 16 exploratory wells, 14 were successful, with 2 dry holes giving us an 88% success rate in 2003. $3.2 million was spent for exploration acreage. We still plan to spend $100 million on our drilling program for this year.

Now, our core properties starting with East Texas North Louisiana region, page 15. The drilling results for East Texas North Louisiana. We spent $4 million and drilled five wells in our East Texas North Louisiana region in the first half of this year. Four of these wells were successfully developmental wells and one was an unsuccessful exploratory well drilled in Richland Parish in North Louisiana. Three of these wells have been tested at a per well average rate of 1.9 million cubic feet equivalent per day. The remaining well is in the process of being completed.

Our Southeast Texas regional drilling results, page 16. In our Southeast Texas region, we have drilled two wells so far in 2003 to continue to delineate our Hamman discovery made last year in Polk County Texas. In the second quarter, Comstock drilled a Hamman number 2 well and the Collins number 2 well. The Hamman number 2 well was drilled to a depth of 15,400 feet and encountered only six net feet of pay in a Woodbine formation and is expected to be a marginal well. The Collins number 2 well was drilled to a depth of 15,525 feet and discovered approximately 52 net feet of high porosity pay sands in a Woodbine formation. Completion operations are currently underway on this well, which is expected to be another very high volume producer. We own a 58% interest in both of these wells and we operate both of these wells. We have recently arranged to acquire 75 square miles of 3-D seismic over our Ross and Robin prospects as well as at Anadarko's discovery south of the Hamman. We now plan to wait until next year to drill the Robin prospect so we can analyze this new data. Page-17 - the Hamman and Collins production. The Hamman number 1 was drilled to a depth of 15,788 feet and was connected to cells on October 18, 2002 at a daily rate of around 19 million cubic feet equivalent. This well continues to produce at that rate with no decline. The Collins number 1 was put on production on June 6, 2003, and is currently producing 15.5 million cubic feet equivalent per day.

South Texas exploration program, drilling results, page 18. We spent $9 million and drilled six wells in our South Texas exploration program in the first half of this year. Five of the six wells were successful. Three of these wells were successful discoveries on the Ball Ranch in Kennedy County, Texas. An addition to the two successful Ball Ranch wells previously reported, the Clark Sain (ph) number 7 well was drilled to a total depth of 12,950 feet and found approximately 40 feet of net pay. This well was recently tested at 5 million cubic feet equivalent per day. We have a 20% working interest in the Ball Ranch well. We also drilled the Lopez number 1 in Star County to a depth of 8,500 feet and discovered approximately 50 feet of net pay in a big spurt formation. This well was tested at 4.5 million cubic feet equivalent per day. We operated on a 57% working interest in this discovery and probably the largest discovery to date for us in South Texas is the Miller number 1, which was drilled at Patterson Ranch in Live Oak County. The Miller number 1 was drilled to a depth of 14,100 feet and discovered approximately 90 net feet of pay in the Wilcox formation. We operate and have a 58% working interest in this discovery, which is currently producing at a rate of 10.4 million cubic feet equivalent per day. We have a significant inventory of 3-D seismic and generated prospects in South Texas and net reserve potential of over 125 Bcfe. We plan to drill eight more wells in this region by the end of the year.

The Gulf of Mexico, page 19, the drilling results. We have spent $22 million in the first half of this year in the Gulf of Mexico and drilled nine wells under our exploration program with Bodark offshore limited. All of these wells were successful. In addition to the four successful offshore wells we drilled in the first quarter, we made five discoveries in the Gulf of Mexico with Bodark in the second quarter. The most significant discovery made in the quarter was made at Ship Shoal block 109 where we drilled a well to test the Oak Monte prospect to the total depth of 12,325 feet and found 13 gas bearing zones in the middle to lower ply seen sands with 192 feet of net pay. We also made a discovery nearby Ship Shoal block 110 when we drilled to test the Pebble Beach prospect. This well was drilled to a total depth of 11,996 feet, and found 116 feet of net pay. We have a 36.5% working interest in these wells, which will be connected to a common platform to be set in early 2004. We also drilled successful wells at South Timbalier block 11, with the (inaudible) 16945 number one well in which we have a 33% working interest and at Ship Shoal block 146 with the OCS-22705 number two well, in which we have a 40% working interest. These wells will be connected to existing production platforms during the third quarter. The remaining well was drilled at South Timbalier block 30 where we have a 34% working interest. The OCS-G 13928 number seven well was a successful well which follows two earlier discoveries made in this same block.

A new facility should be installed in September at South Timbalier 30, with first production expected in early November of this year from the three wells. We are currently drilling the first of two planned delineation wells at South Pelto 22 to follow up on the significant deep shift discovery well that was drilled in the first quarter of this year. We own a 29% working interest in South Pelto 22, with Bodark the operator owning 21% and stone energy owning the balance. Our 2003 outlook, page 20. outlook for the rest of the year. We expect our production to increase to somewhere between 10% to 15% over last year. After drilling operations in 2002 and the first half of 2003 has resulted in a substantial number of projects that are waiting on the installation of facilities prior to being brought to sales. We currently have 12 wells that have been drilled that are expected to be able to add 25 to 30 million cubic feet equivalent per day to our net production rate.

These projects are expected to come on line at various dates over the next three quarters. We still plan to spend $100 million on our drilling program this year. With over half of our budget going for high impact exploration projects, we also have substantial up side in our multi-year inventory of drilling prospects in the Gulf of Mexico and South Texas. And lastly, with the improved natural gas prices, we should continue to generate substantial cash flow in excess of our capital expenditures, which will allow us to continue to pay down our debt and enhance our balance sheet. And with that, Monica, I will turn it over to questions and answers.

Thank you, sir. We will now begin the question and answer session. If you have a question, you will need to press "star 1" on your touchtone phone. You will hear an acknowledgement that you have been placed in queue. If your question has been answered and you wish to be removed from the queue, please press the # sign. If you are using a speakerphone, please pick up your hand set before pressing the numbers. Once again for any questions please press "star 1" on your touchtone phone. First question comes from Van Levy from CIBC. Please go ahead.

Good morning, gentlemen, how are you?

Good morning, Van.

I thought it was very interesting on the Anardarko call with all the exploration that they had to talk about, that they spent a good bit of time on the Woodbine play, which to my knowledge you guys were there about three years before them with the Double A wells field. So it's pretty interesting. Congratulations on that and hopefully you can figure out how to get their historic you know 8 to 10 multiple. Question, on the well that, I guess the Hamman number 2 that only got 6 feet of pay. Post mortem, what do you think happened in the process? How do you improve your decision-making? Is it one of those things statistically that is going to happen?

Van, this is Mike Taylor. I think, what we think has happened on that, what we found, we found 6 feet of pay, it's probably not equivalent to the sand that produces out of the Hamman number 1, and the Collins number 1 and what we found on Collins 2. It is probably, a remnant of what we see in Double A and one of the pay zones up there. So it, while it should be productive, it should be considered probably part of a Double A rather than part of the new discovery. So we are reevaluating that acreage in the context of, perhaps that sand thickens, and perhaps covers more of the acreage than we thought before. But I think what it does it obviously gives us a better idea of where the sand is not, in the Hamman discovery area. But I think with the thickening of the sand that we see in the Collins 2, we are optimistic about future development down in that direction.

Van, one other comment. If you look, we kind of have a sheet on this. If you look at what we've done in the area, you start with Double A. And then you look at the 2D success we had there and the 3-D success. We came down and we drilled the Hamman number 1 based on 3-D seismic, of course, the Hamman 2, and the Collins 1, and the Collins 2. If you look at the net pay we had when we drilled the Hamman number 1, we had 37 feet of net pay, and we say net pay that's greater than [9%] porosity. So then if you remember, we drilled the Collins number 1, and it had 41 feet of net pay. So it had greater pay, but we had to [Frak] that well. We thought the well would be an 8 to 10 million a day well in fact it's producing a little less than 16 million a day. It’s a really good well, which is new news, because we have not reported that at all. Then we drilled, of course, the Hamman number 2 and as Mike said, what they think is, we had a [inaudible] number 3 that is the same reservoir, we think. That well is a 2 to 3 million a day well that is [carrying] maybe 3 or 4 Bcfe of reserves. So we call that a marginal well and versus what we expected to find.

Then we drilled the Collins number 2 and we find 52 feet of net pay, which is greater than 9% porosity and then go south, and as we discovered that, and, you know, we were told that Anadarko hit a well that is you know maybe at 35 million or so a day test rate net. We don't know that for sure, that's what we have been told. So what we did on the Robin and the Ross, really the Robin prospect and even the Ross, too, the further southwest, if we had been so successful in Double A with 3-D, we should apply this same technology to our Robin area. If you remember, in Double A we drilled six wells based upon 2D seismic and hit 4 of the 6, we had 2 dry holes. We waited a of couple years, we shot the 3-D and then we drilled 22 wells based on 3D and we hit 19 of those, and what we’ve said here is that we are not afraid to drill a well on the Robin prospect at all right now. We would like to drill one or two right now without the seismic. But with it, it might be that we would want to own a little more interest in it because there has been, you know, there has been such great success to the south.

Now, you always have an [inflation] issue, but it looks like the sands are thickening as they go south and currently the 4,000 plus acres that we own south, we own 100% of it and we don't have any partners in it. So we are going to use this tool to evaluate that, and at the same time, maybe we did pick up the stringer that [indiscernible] at 3 reservoir, which is a Double A field and the Hamman 1. But we have been cautious on that and really, it is developing into something, maybe a little nicer than we thought it might be. It's been a pleasant surprise.

Remind me what the potential is on the Robin again?

Well, I'll -as far as the reserve targets?

Right.

We'll drill that well to 20,000 feet, let's say. And I don't know if we've given out any -

4,000 acres. So if you take kind of, I don't know, 50, 60, 70 feet of pay.

Say a couple of hundred BCF is the prospect target for Robin.

Van what we said is in Double A, I think when we bought Double A and became the operator, it had [indiscernible] about 78 Bcfe of reserves and through last year it had [indiscernible] about I think 330 to 350 Bcfe and we think that you know that might be a 600 Bcfe field. And then we look at the - actually look at the Ross area and say that's 100, 150 Bcfe maybe and then we look at the Robin and say that's you know a 2 to 300 Bcfe. You don't really know until you drill it. That's kind of what we speculate.

OK. Second question, it looks like production, and I guess in East Texas, you know, has dropped year-over-year, and South Texas on the oil side and certainly East Texas on the gas. What is the, at these prices, why would that production be dropping? Is it simply capital rationing? Directing a higher rate of return, other higher rate of return areas?

Especially in East Texas, Van, where we forecasted those declines are in line with our forecast, although we did just drill some wells in East Texas. So you should see that decline maybe -- shouldn't see any decline in the third quarter, but it is mostly capital rationing. It's really those -- East Texas for us now, it used to be the heart of the company's development program, is now our most, lowest return area. And if you compare it to the opportunities in the Gulf or South Texas or the Double A wells field, they are just vastly inferior returns. So it's a big part of our goal, one of our big goals this year is to transform the balance sheet and get us to where our debt is less than half of our book capitalization. So we have limited our drilling budget to $100 million, and we are going to pay down debt, and East Texas is the one that has to pay the price, and not get much of the capital.

Remember, in each of 2000, 2001, 2002, we spent about $18 million each year, and drilled about 18 wells, and we said this year we spent about $8 million. A lot of that would be re-completions and some of them would be new wells that we would drill. We did drill five wells in the first half of the year, and four were successful. But our production rate is a little higher. We have typically averaged between 1.5 and 1.8 million for initial well test. We were at 1.9 million in the first six months here. But we have intentionally not plowed a lot of money in those areas like Roland said, we want to stick with this $100 million CAPEX budget and use the rest of the money to pay down our debt. And we really have just better places to spend our money.

Okay. Last question, economic returns are very, very good. I'm taking cash flow this quarter of about 333 divided by your [DDA] rate, by about 40. You get 137%, do the same calculation in 2002, it was 32% market difference. Clearly it's because prices are up. Certainly it's down a little bit from the first quarter. Obviously, if you hedge, you can lock in some very stout margins, and you are not subject to the big swings in cash and cash returns. I know your debt is going down, which mitigates the need for you to hedge. But what are your thoughts now, Jay?

Well, our attitude is still the same Van. We look at commodity prices today. They are really the current strip is $5. I think the injection rate is 74, 73 or 74 BCF today. We still think that we should be in hedge because we still think that in our model, we said if gas averaged 450, we would have a real good year. If it averaged $6, we would have a better year. So far the first six months, we averaged a few pennies under $6 for MCF I think we are still comfortable with what we are doing. However, we do look and every time we visit with you we talk about it.

You have had one of the highest realizations this quarter also. So Great, good job. Keep it up.

Thank you.

Our next question comes from Wayne Andrews from Raymond James. Please go ahead.

Good morning, gentlemen. A couple of quick questions. But all in all it looks like a very encouraging quarter for you. You mentioned, Jay, that you were going to go ahead and participate in the 3 D shoot. Did you say that that's going to cover not only Robin, but does it cover Ross as well, did you say? And as well as the Anadarko well?

Yes, what we've done is, we kind of mentioned this a month or two months ago. Dominion has big acreage position around our acreage, and then as you know, Anadarko has and dominion has agreed to participate in this chute, Anadarko had drilled this well. And I think they spent $11 million or so drilling a well south of where we were, and I think they elected to participate in the seismic. And once they did that, then we, you know, we as a company said we should probably go ahead and participate, and then even though they were delayed in the drilling of the well, we feel like, we looked at the impact of the seismic, we received on Double A and the success rate we had. And we said if it can cover part of the Ross acreage, which it does, if you look on page 16 on the web page you can see where the new 3-D seismic will cover. And it covers the southern part of the Ross acreage. It covers all of the Robin acreage. It covers a little bit where the Anadarko well is so…

My question is really regarding the plans to continue drilling in the Ross area for the remainder of the year. I think you plan to drill maybe five wells there, and your three additional wells, so far this year and you plan to drill another two there in the remainder of the year?

Yes, we said at the beginning, we’d drill five wells, and we drilled two so far. We want to drill a well probably, to the south of the Collins two and then we’ll drill a vertical well offsetting the Hamman number two. We know we'll do those two, and we’ll wait on the results to see what happens, to drill the third well.

Very good. I was just wondering if you were going to change your plans because that new 3-D was covering the Ross. But --

No, Wayne, we talked about that. But we said again we think that the delta is to the south of where the Collins two is. We have been wrong before, but we have been right also. So we do want to drill a well there and then we would like to drill another vertical well offsetting the Hamman. And then we would connect up the Hamman 2 with the vertical well that we'd be drilling

Great, any other discussions? I know it's still early, and you just started your second well at South Pelto 22, but any other discussions as far as where those volumes might flow to, by the end of the year or early in --- early next year?

Well as far as the time frame no, I'll let Mike address the [inaudible].

We have had meetings with Bodark and Stone. And you know we’ve all agreed that, there's a lot of, you know, issues that were brought up. But what we all agreed to do is, we would agree to drill this number three well, which remember that the number one well was the dry hole that Stone had drilled. And so the number two well was the can of corn well, so that the number two well really is our first well out there, but it is called the number two well. We are going North, Northwest to drill the number three well and that well was [spuded] I think last Friday. And the number two well took 40 days to drill, and that's probably an exception. So we would say it probably will take two months to drill these wells. But we did spud that up late last Friday. So that's the number three well, and then will come, and we’ll offset the number two well and we’ll drill the number four well, and if those are successful than we will -- when we drill the three well, we'll drill and complete it then we’ll move the rig over and we’ll drill the four and complete it and then we'll complete the number two well, and some of that had to do with depletion. I mean, we didn't want to have drilling problems from the number two with any type of depletion that we might have had so we have really taken a cautious approach in trying to [prove] up the reserves and having all the wells tested by year-end because that's a reserve issue. We want to try to have them all tested and we definitely think that will happen. And then the goal is, as Stone put out in the press release, to have production in the first quarter of '04. And that's really what we think will happen. We've given a little wiggle room in there, too, Wayne, if we have any interruptions with bad weather, with hurricanes. As far as the facilities, do you want to address that, Mike?

I don't have a lot to add to what has been put out there by Stone and MMS, but there will be two platforms, one major facility and one platform over the existing number two well. And pipelines associated with that will flow to our own gas market there. Well have a line that is permitted to go over to Pelto 23, the Stone platform as a just in case kind of situation. But we plan to -- Bodark plans to produce from those platforms directly to market.

Great, very good and I have just -- one last question, you mentioned two additional discoveries that also sound very encouraging at Ship Shoal 109 and 110. That might be early 2004 production also. I take it those two discoveries are significant enough to warrant a platform installation there and that's what the timing is related to?

Yeah, that's correct, Wayne, especially the Oak Monte prospect. It looks like the largest of the two. They will share a platform and we’ll need a new production platform to be set there. That's, that will be designed and then see that also as a probably a first quarter 2004 production coming on line.

Remember, the Oak Monte, which is the Ship Shoal 109 that was 192 feet of net pay.

Sounds like a great well.

There's a lot of really good wells out of the five that we drilled in the Gulf that are not -- we haven't really been that vocal about them. They’ve all blended in together, but as far as the best success we have ever had in any say four months of drilling because that would include Pelto 22.

The Ship Shoal 109/110 area are also part of a, we have invested in reprocessing some proprietary seismic we have got in that area which mainly covers Ship Shoal 113, the properties we purchased last December. And they think that's going to open up some new exploration ideas for that whole area. So that should be a big focus of what we do next year, we think will be that Ship Shoal 113 and 110, 109 area. We'll start to drill some of the shallower low risk projects at 113 here, start as early as September and try to have some of those done, at least three of those done by the end of the year.

Remember that was that 40,000-acres that we acquired December of last year when we wanted to reprocess the data. So when we reprocessed the data, fortunately it overlapped into 109/110. So we will get to look at the new reprocessed data on that as we develop those two areas. And like Robin said, we should hopefully drill and complete three wells in the 113 area between now and year-end. We should drill another, you know, six or seven wells offshore this year. And we plan on drilling one more, you know deeper [indiscernible] test well similar to this Pelto 22 type area this year also. So we'll have that going on.

Sounds very encouraging. Thanks for the update.

Alright, thank you, Wayne.

Next question is from Fadel Gheit from Fahnestock & Co. Please go ahead.

Good morning, how are you?

Few questions. Do you have an estimate for your average S and D costs so far this year?

I don't believe we do. Roland?

We aren't providing that yet. This is a function of the exploration success in the reserves booked and we're going to – not have our hands totally around that till the end of the year. But we are real encouraged with the, of course, with the high drilling success rate and most of our budget is going for exploration, which should be adding new reserves.

Right, the other thing, give us an update on the Bodark program. Where are you now in terms of money spent and time covered?

Roland, do you have in front of you?

We don't really have that in front of us. What happened with the original Bodark acquisition was kind of expensive as our ticket into the Gulf of Mexico. But where you're seeing all the benefits and fruit has been with the exploration program, which, you know, now that it has been in place for five or six years, has generated a consistent, you know, success rate. And this year is probably our most successful year ever with Bodark.

I think we have, from say 1998 through the end of the second quarter, I think we drilled about 89 wells in the Gulf of Mexico. And the vast majority of those have been through the Bodark program and we’ve hit about 68, I think 68 of the 89. So we've got the mid 70% success rate there. I guess if you take the last nine months, though, we've only had a couple of dry holes. It seems like the more money we spend to reprocess data in a core area, the better success rate we have had. Like when we picked up the 40,000 acres from Murphy in the 113 area, what that allowed us to do, that was in December of last year. That allowed us to come in and pick up almost another 60,000 acres in that same core area. Kind of connect the dots in the core area there. We ended up with about 137,000 acres and with about 80 prospects in that area, all because you just stick in that one area and reprocess the data and drill wells and then reprocess it. And our success rate with Bodark, I attribute a lot of that to just staying in a core area with the same people over and over and over. I don't know if Roland has real numbers on that, but, you know -

No, I was just trying to get an order of magnitude. Has it been below industry average in terms of finding costs? Have you been successful in increasing the size of the discovery? The cycle time? Whatever, you know. Something that you can, you know, report card, if you will, after five years of marriage, as they say. Good marriage, bad marriage or like every other marriage -

I think you would definitely say it's a great marriage. I think that our finding cost speak themselves right below industry average, especially for the Gulf of Mexico. At about $1.15 type finding cost out there.

OK.

I think it's just gotten better and better, especially now with the focus on reprocessing seismic and the focus really on the deeper shelf, like South Pelto 22. That's the real high impact stuff.

Then very quick two more questions. What would be the depth level target that you are looking at, Roland, say at the end of this year or the end of next year.

End of this year, we think that we do have our [path] set on getting to at a minimum 52%, debt to book capital. There's a good chance we will get to the 50% level. It really depends a little bit on gas prices, how strong they stay, the rest of the year. But we’ve stayed ahead of our debt pay down plans. In the third quarter, this will be a real big quarter for debt pay down, as you saw in July when we paid down $13 million. This will be a real big quarter. We’ll probably be able to do that at a minimum, $25 million can probably be paid down in the third quarter.

OK. And what makes you, Roland, what would be the trigger point? You say OK, I'm not going to drill this well. I'm going to pay down debt. What do you look for? What economics do you use to decide which way to go?

Well, the one thing I would comment on that is, remember we have $220 million of 11.25% bonds that are callable in May of '04. And really our goal is to call those May of '04 and try to get 7.5%, 7.75% money versus 11.25%. We visited with the rating agencies in February or so and the rating agency instead of a negative outlook gave us a stable outlook, both of them, S&P and Moody’s. And we told them we’d pay down our debt and stick to this $100 million in CAPEX. That combined with the success rate we’ve had and you know – possibly at least $30 million a day of net production that we should add in the next three quarters. You know our goal is to get rid of that extensive debt and maybe save as much as $9 million in interest expense by having some new debt out there. And we've already saved $1.6 million in the dividend with the convertible preferred converting into common. So we look at that, too, as kind of a Bogey out there when we look at our drilling prospects, our debt pay down.

And then finally, are you looking, when you look at the current property prices, are you as being a reflection of higher natural gas prices or lower or flat from where we are?

As far as, yeah, as far as acquisitions?

Right, right.

We view that, yeah, the cost of quality producing properties definitely has the higher natural gas prices built in and we view them as pretty expensive now to acquire. That's why we've really focused on, we think we can find reserves a lot for a lot less cost through exploration. That's why we are putting our capital there. When prices turn around and go into a low period of natural gas prices, then maybe that equation turns around where it's better to buy them. We think it's clearly better in the long run to try to drill reserves now than to try to buy them in the market.

OK, thank you.

Thank you.

Our next question comes from Ron Mills from Johnston Rise. Please go ahead.

Good morning, guys. As it relates to the Ross project area with the Hamman number 2 well coming in the way it did, do you think then as you continue to move northwest that -- I'm just looking at an old slide where you had this year's locations. Did the locations to the northwest become less appealing to you going forward?

Well, I think what we have to do on the northwest, Ron, is we have to drill a vertical well at Hamman and to do that and see what kind of sand package we get and we want to do that this year. We were going to drill a well south of the Collins number 2. We are comfortable with that. And then if the vertical well at Hamman comes in, then I think it's probably $500,000 to Frak and lay a pipeline over to the Hamman number 2 well. And even though we call it a marginal well, I mean hopefully it will be a decent well. We don’t know - we didn't get a lot of pace and hopefully we can Frak into some sand.

They are looking towards the south and the new 3-D seismic -- see, actually the data in the south gets a poor quality because you are at the tail of the old 3-D seismic survey and then it totally drops off. So the new 3-D that’s going to cover all of Ross and everything to the south, we think it's going to open a lot of newer prospective areas down there and that there will be this additional well drilled. Like Jay talked about, which it might develop out this Alabama Cashada sands that is above the Hamman sand. That may turn into a nice play. That's what this next well is going to tell us.

That Hamman well, the vertical well actually will be to the north because the drill side was to the north, outside the thicket. There was a directional well and the bottom hole that you're looking at in that old map is the Hamman 2. But that's the bottom hole location. The drill rig location is to the north outside the thicket.

It won’t be in the actual -

That well will be from the same drilling pad as the Hamman 2, except it will be a vertical well.

All right. Is there any chance then that on the well you planned on drilling south of the Collins number 2, that you end up waiting on the new 3-D data for that well as well?

No.

We want to drill another well to the south of the Collins 2.

We are going to drill at least two more wells this year, Ron.

Just because -- yeah, just because of the Collins 2 is so strong with the sand actually improving there.

Ron, you can map it out. The Hamman number 1 you get 37 feet of sand and you go north, the Hamman number 2 you only get 6 feet. But then you go to start coming, you go west a little bit, you get 41 feet. But you come south of the Hamman number 1, and you have 52 feet of net pay sand. That's -- I mean, that's the best pay sand we have had. Now, again, you always have to look at a depletion issue. But we do think the sand thickens because that well tells us it thickens to the south. You know, you connect that with the Anadarko well, with the Kirby well, with the Arco well. There is some control there. But we just – we have had great success for 3-D in that area. That's what made Double A as great a field as it is.

Right. And as it relates to South Pelto 22, taking the conservative stance, you, part of the concern would be for depletion problems. What is that related to in terms of -- what was the risk in -

You're referring to, Ron, as far as that, if you are drilling through a depleted reservoir, you encounter a lot of, you can encounter a lot of drilling problems and lose your - and actually that is where you see a lot of problems out there is when you drill through this depleted zone and then you lose your -

You can lose the circulation - what happens, we said if we drilled, if we complete the number 2, before we drill the number 4, and we wanted to drill the number 3 as the next well. All had agreed upon that. So the dilemma was, if we completed the number two, where would we produce it? And even more important question is, if we had a really good location on, as the number 4 location, would we want to jeopardize a drilling problem. If we drill the number two and completed that number two well, then we drilled the number four and we drilled through that sand that's producing and there's depletion and that depletion hits the drill pipe of the number four well, then you can lose circulation and get stuck in the hole. You can lose millions and millions and millions of dollars in drilling that well. Example, I mean our well costs $7 million to drill, which is a can of corn well and the stone well was $13 plus million or so. And that's normal, really. Because you can, it is so easy to have a drilling problem out there. And what we as a group said, let's just avoid that possible problem and let's wait and drill them all and complete them all and have them on in the first quarter.

Basically the number four well plans on drilling to a deeper, to a target than you had in the, at least that you expect to produce in the number 2?

Well, you'll drill the three and if the sand comes in in the number 3 well, the number four well will be drilled deeper.

And than Roland, just one financial question, or a couple on the notes that can be redeemed beginning next May. What type of premium would that have in terms of the redemption price?

I think in the first year when the call is available, it's like 105, 25, a little more than 105% premium. That goes down each year, if you keep it out, if you wait an additional year to call it.

OK. We have a pretty good sense on production guidance for the remainder of the year. How about on the cost side, are the second quarter unit costs a pretty good proxy for what you expect the remainder of the year?

They probably are. I think the corporate G&A was a little high. The second quarter we had some recurring items.

Yeah.

I think more like the first quarter G&A is probably a better proxy, maybe an average between the two. But as far as lifting costs, it’s been pretty consistent. And the difference is really the severance in production taxes as it relates to the gas price that we incur. So if we are, you know, it's about this dollar all in lifting cost with gas and, you know, roughly $5. If you go above that, then you’re going to have a little higher lifting cost. If you go below that, you'll have, you know, you'll get down to a lower, maybe about 90 cents or something if you had a $4 gas price.

All righty, thanks a lot, guys.

Thanks, Ron.

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

Good morning, guys, real quick question on Collins number 2. Just in terms of timing, when should we expect that to come on line, that's number one. Number two, any sense as to the, what could a capital spending program for next year look like and just some broad thoughts as to -- where that capital will be focused, maybe by area, if you will. Thanks.

At the end of this month, Rehan, we hope to get the Lopez on line, which is South Texas, and we hope to get the Collins two to sales. That's our goal. I visited with [Matt Goode] probably an hour and a half ago to see if that could be done and we think that that will happen. So that's a target that we have. And as far as CAPEX Roland, you want to discuss that?

Yeah, we are probably, we haven't set our cap ex budget for next year, but I would say that we’re - in preliminary thinking it would be up a little bit from this year - probably $120 million. But we will have to really look at is, as we get toward the end of the year, you know what’s the outlook for gas prices, and the strength of the gas price environment. When we start to set the budget, cause that going to dictate whether we are $80 million, if we have very low prices to, maybe $120 million if we have high prices.

OK, thanks.

I’ll still want to taylor our drilling expenditures to, to fall within our cash flow that is generated from operations.

All right, thank you.

And Mr. Allison, I've not seen actually not showing any more questions at this time.

All right. Again we would like to thank you for listening to the conference call. If you have any questions later on, give us a call. If not, thank you.

And ladies and gentlemen, this does conclude our second quarter financial results conference call. You may all disconnect. Thank you for participating.