Comstock Resources Inc (CRK) 2003 Q3 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the third 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. Good morning, everyone. Welcome to Comstock Resources' third-quarter 2003 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 Third Quarter 2003 Results. To change the page in the presentation, you click on the arrow on the page.

I am Jay Allison, President of Comstock, and with me this morning is Roland Burns, our Chief Financial Officer, and Mike Taylor, our Vice President of Corporate Development, who will help answer questions today.

With this call, I will review our third-quarter 2003 and nine-months ended September 30th, 2003 financial results, as well as 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 2 on the webcast -- on the call today, we will review our third-quarter financial results, where we generated a net profit of $12.9 million, or 36 cents per share. Strong oil and gas prices and a 13 percent increase in our production were the primary contributors to the solid results for the quarter. In the third quarter, we continued to improve our balance sheet, and we were able to lower our debt-to-capitalization ratio to 53 percent from 63 percent, where it was at the end of the 2002's third quarter. We continued to have excellent results in our drilling program, where we have had 26 successes out of 30 wells drilled in the first nine months, giving us an 87 percent success rate.

We drilled 12 additional wells in Kentucky and in New Mexico that are still being tested and evaluated in the last quarter. Most of these wells are shallow wells. With the drilling successes that we have had, we currently have 25 million cubic feet equivalent per day of new production available to come online when new production facilities are completed. These new wells should be put online over the next three quarters.

Page 3, Oil and Gas Sales. Increased production and strong crude oil and natural gas prices allowed us to realize a sizable increase in our oil and gas sales for the third quarter and the front of (ph) 2003. Our third-quarter sales of $56.9 million were up 60 percent as compared to last year's third quarter sales of $35.6 million.

For the first nine months of this year, our sales totaled $182.6 million, an increase of 83 percent over sales in the first nine months of last year of $100 million.

Page 4, EBITDAX. Earnings before interest, taxes, depreciation, amortization, and exploration expense, or EBITDAX, increased 82 percent in the third quarter to $43.6 million as compared to $24 million in the third quarter 2002. EBITDAX in the first nine months of this year grew 105 percent to $144.1 million as compared to $70.4 million in the first nine months of 2002.

Page 5, Operating Cash Flow. Our cash flow from operations increased 123 percent in the third quarter of this year to $36.2 million from $16.2 million in the third quarter of 2002. Operating cash flow for the first nine months of this year was $121.5 million, up 151 percent from cash flow of $48.5 million for the same period last year.

Earnings on page 6. We reported a net profit of $12.9 million for the third quarter of 2003 as compared to $3 million for the third quarter 2002. For the first nine months of this year, we had net income of $47 million as compared to net income of $1.5 million for the first nine months of 2002. We had 36 cents in earnings per share in the third quarter as compared to 10 cents per share in 2002's third quarter. In the first nine months of this year, our earnings per share was $1.36 as compared to 5 cents per share for the first nine months of 2002.

Production, page 7. Production in the third quarter averaged 123 million cubic feet equivalent per day, which represents a 13 percent increase from 2002's third-quarter production level of 108 million cubic feet equivalent per day. We averaged 39 million cubic feet equivalent per day in our Gulf of Mexico region, 39 million equivalent per day in our southeast Texas region, 28 million equivalent per day in our east Texas/north Louisiana region, and 20 million equivalent per day in south Texas and other regions during the third quarter.

Page 8, Average Oil Price. Our average oil price realizations were up in 2003 as compared to the same period last year. For the third quarter of 2003, our realized crude oil price increased 8 percent to $29.50 from $27.30 for the third quarter of 2002. For the first nine months of this year, our average oil price increased 27 percent to $30.79 as compared to $24.16 for the same period in 2002.

Page 9, Average Gas Prices. Gas prices have increased significantly in 2003 over last year. Our average realized gas price in the third quarter was $5.04, 52 percent higher than our third quarter 2002 average price of $3.31. For the first nine months of this year, our gas price averaged $5.65 cents, 85 percent higher than our average price of $3.06 for the first nine months of last year.

Page 10, Cost per Unit of Production in the Third Quarter. Our lifting cost per Mcfe increased to $1.04 in 2003's third quarter from 79 cents in 2002's third quarter. The increase is attributable mainly to higher production and ad valorem taxes related to increased oil and gas prices. Our G&A expense per Mcfe increased to 13 cents in the third quarter of 2003 from 9 cents for the third quarter of 2002. The increase is attributable to increased personnel cost as we have expanded our technical staff, including opening a Houston offshore office this year. Depreciation, depletion, and amortization per Mcfe produced has increased by 7 cents to $1.33 for the third quarter of 2003 as compared to $1.26 for the same period in 2002.

Page 11, Cost per Unit of Production Nine Months Ended September 30th, 2003. Lifting cost per Mcfe produced increased by 23 cents or $1.02 for the nine months ended September 30th 2003 from 79 cents in the same period in 2002 -- again, mostly due to higher production and ad valorem taxes attributable to the higher oil and gas prices in 2003. Our G&A expense for Mcfe increased 5 cents in the first nine months of 2003 to 15 cents from 10 cents for the same period in 2002. Depreciation, depletion, and amortization for Mcfe produced has increased by 7 cents in the first nine months of 2003 to $1.35 from $1.28 from the same period in 2002.

Page 12, Cash Margins. Due to higher oil and gas prices, our cash margins per unit of production increased 45 percent in the third quarter of 2003 to $3.84 per Mcfe as compared to $2.65 in 2002's third quarter. Our cash margin for the first nine months of 2003 grew 86 percent to $4.37 cents per Mcfe as compared to $2.35 cents per Mcfe for the same period last year.

Page 13, Capitalization -- looking at our balance sheet. At the end of our third quarter, our debt has been reduced to $311 million. $91 million was outstanding under our bank facility, which has a $260 million borrowing base, giving us $169 million available under the credit facility. The balance are 11-1/4 percent bonds, which are callable next May. Debt as a percent of our total book capitalization has fallen from 63 percent at the end of 2002's third quarter to 53 percent at the end of this quarter. To date, we have been able to reduce our debt by $55 million from excess cash flow from operations.

Capital Expenditures, page 14. In the first nine months of this year, we spent $60.6 million on our drilling programs as compared to $57.7 million in the first nine months of 2002. We spent $15.1 million to drill 16 development wells, all of which were successful or are still being evaluated. We spent an additional $12.4 million for workovers and recompletions, offshore production facilities, and other development costs. We spent $33.1 million on our exploration program. $29.4 million was spent to drill 26 exploratory wells. 17 were successful, with four dry holes, and five are being evaluated, giving us an 88 percent success rate in 2003. $3.7 million was spent for exploratory acreage. We're still planning to spend between $95 and $100 million on the drilling program for this year.

Page 15, East Texas/North Louisiana Region Drilling Results. We have spent $5 million and drilled five wells in our east Texas/north Louisiana region in the first nine months of this year. Four of these wells were successful developmental wells, and one was an unsuccessful exploratory test drilled in north Louisiana. The successful wells have been tested at a per well rate average of about 1.7 million cubic feet equivalent per day. We expect to drill one more development well in this region by the end of this year.

Page 16, our Southeast Texas Region Drilling Results -- in our southeast Texas region, we have drilled two wells so far in 2003, and continue to delineate our Hamman discovery made last year in Polk County, Texas. The Collins Number 2 well was put on production in September, and has averaged 5.6 million cubic feet equivalent per day in daily production since that date. The Hamman Number 1, Collins Number 1, and Collins Number Two wells are currently producing at a combined rate of 35.1 million cubic feet equivalent per day. We own a 58 percent working interest and operate these wells. Two additional delineation wells are planned by year-end to further develop the Hamman discovery. We are awaiting the receipt of new 3-D seismic data to continue our exploration at the Ross Prospect and to test our Robin Prospect.

Page 17, our South Texas Region drilling results. We spent $10 million and drilled 12 wells in our south Texas exploration program in the first nine months of this year. 8 of the 12 wells were successful. Three were dry holes, and one is still being evaluated. Six of these wells were drilled on the Ball Ranch in Kenedy County, Texas. We have a 20 percent working interest at Ball Ranch. We also drilled the Lopez Number 1 in Starr County and the Miller Number 1, which was drilled in Patteson Ranch in Live Oak County. Two dry holes were drilled in the third quarter, including the Taylor No. 1, which tested the Encidino (ph) prospect, and the shallow well at the Mills Bennett (ph) Ranch. The successful south Texas wells have averaged 7 million cubic feet equivalent per day for their initial production rates. We plan to drill two more exploratory wells by the end of this year, including another well at Ball Ranch and a test well in Matagorda County to test our Wadsworth Prospect, which has a 60 Bcfe target. We own a 45 percent working interest in this prospect.

Page 19, Gulf of Mexico drilling results. We have spent $36 million in the first nine months of this year in the Gulf of Mexico, and drilled 12 wells under our exploration program with Bodark (ph) Offshore Limited. All of these wells have been successful. In addition to the nine successful offshore wells we drilled in the first and second quarters, we have had three additional successes in the Gulf of Mexico with Bodark in the third quarter. As Stone Energy reported yesterday, the first delineation well at South Pelto block 22, the number 3 well, was drilled to a total true vertical depth of 18,155 feet at a bottom hole location approximately 1,700 feet southwest of the discovery well. The number 3 appraisal well logged 205 net feet of pay in eight sands in a fall block adjacent to the fall block that was tested by the number 2 discovery well.

Following the completion of the number 3 well, we will move the drilling rig over to drill the number 4 well from the surface location adjacent to the number 2. The number 4 well is planned to be drilled to a depth of about 18,000 feet, up depth (ph) from the number 2 discovery well. A four-pile production facility is currently under construction, and is anticipated to be installed in the first quarter of 2004 to allow production startup in the number 2, the number 3, and the number 4 well if it is successful.

Additional exploration in exploration in South Pelto 22 is planned in 2004 along the same major fault that traps the discovery. We have a 29 percent working interest in the South Pelto 22 Number 2 and Number 3 wells.

We also have another deep shelf discovery at a nearby block in South Pelto. The well has been drilled to a true vertical depth of 16,200 feet, with the first two objectives demonstrating the presence of commercial hydrocarbons. Protective casing will be set over the pay found to date, and drilling will resume in the next several days to deepen the well by another 1,000 feet. We expect to drill several more deep wells in this block in 2004 to test several additional faults that have been identified. We have a 24.9 percent working interest in this deep-shelf discovery well.

Our first well, as part of a redevelopment and exploration program at the Ship Shoal 113 unit, was also successful. The OCSG 40 (ph) number 5 well was drilled to a total depth of 8,000 feet, and logged approximately 63 net feet of pay in three sands. We have a 72 percent working interest and operate this well.

We currently have four offshore rigs working for us, which will allow us to drill seven additional offshore wells, including the number 4 well at South Pelto 22 by year end.

Page 19, 2003 Outlook -- Outlook for the Rest of the Year. Our production is expected to continue to increase over the next three quarters as we are able to connect more of the offshore discoveries that we have made to sales. We currently have 11 wells that have been drilled that are expected to be able to add 25 million cubic feet equivalent per day to our net production rate. These projects are expected to come online at various dates over the next three quarters.

We still have another 20 wells to drill to complete our 2003 drilling program, and we have four offshore rigs under contract for the rest of this year. We also have substantial upside, with our multiyear inventory of drilling prospects in the Gulf of Mexico and in south Texas. And lastly, with continued strong natural gas prices, we should be able to continue to generate substantial cash flow in excess of our capital expenditures, which will allow us to pay down more of our debt over the next several quarters and continue to (technical difficulty) our balance sheet. With that, let me turn it over for questions.

We will now begin our question-and-answer session. (Caller Instructions) Wayne Andrews, Raymond James.

Excellent results. It sounds like operations are going well, too, Jay. One quick question -- you mentioned another deep discovery in the Gulf Coast, but I'm not sure you mentioned the block number --?

While we did wind (ph) in this press release, we didn't receive authority from the party that that bar map (ph) came from. What we said in the press release is that we would just say we have another block. We have drilled a well. We think it's another deep discovery. And we would not on the conference call disclose that block. Most of the parties know the name of that block, as we've said it before.

Okay. I think I understand. And I take it there might be competitive issues there, and you don't like to announce these things too early. But that sounds very encouraging, and to be able to put all this volume growth on and reduce debt just sounds outstanding.

Do you have -- you mentioned that your capital spending for the remainder of the year would get you to 95 to 100 million, despite having four rigs operating in the Gulf? It sounds like you increased your activity and still might not spend all the dollars you had allocated.

This is Roland, Wayne. That's correct. As you can see, we've only spent $60 million of our budget so far in the first three quarters. And despite the ramp up in activity, I don't think we can spend our entire budget in the fourth quarter -- although we should have higher spending the fourth quarter than the third. We should be a little under the original budget.

Yes, that's excellent. How do you -- I know you guys hadn't anticipated having four rigs operating in the Gulf. How are you able to do that? And is the pricing still pretty flexible there?

Really, what happened on that -- if you remember, we bought the 40,000 acres at year end last year in Ship Shoal 113. And then we spent about $750,000 to reprocess the seismic. And we hit this well at Ship Shoal 119, which was in that 113 40,000-acre area. And what we said is we will start that drilling program there, and we'll keep our rig busy there between now and year-end, and then carry that program over to 2004.

So that added several wells -- which at the beginning of the year, you never know when that reprocessed seismic will be back. And then, of course, with the deep discovery at South Pelto 22, the number 2 well and then the number 3 well, and then we added this other deeper discovery -- that changed things a little bit. And we kind of got behind on our drilling program because it took about 90 days to drill that number 3 well. So we've just elected to get another rig or two out to try to end the year strong.

Very good. Looks extremely encouraging.

Ray Deacon, First Albany.

Could you tell me how many prospects you have in the Ship Shoal 113 area, and also how many other deep shelf prospects do you think you have in this South Pelto area?

Well, at the beginning, when we had first looked at the 113 area, Ray, there were about a dozen prospects. I think that inventory is at least a dozen, if not a little more than that. And that's -- Mike, you want to add to that?

We're continually upgrading the prospects there. We're looking at it more and more. And we have added some prospect areas. I don't know that we have got them full-fledged drill status at this point. But we had a number of redevelopment projects, like we had on this number 5 well that we just announced. And we have a number of those left to do. And as we drill these, we tend to find more based on the information that we've got on the new wells.

And the real upside at Ship Shoal 113 is in deeper horizons, such as what we're looking about looking at in Pelto 22 and other areas. That area has not been really explored at depths greater than 14,000 feet. So we think there's really some upside there. And we're spending a lot of time trying to build up those prospects at 113.

Okay. And how about in the South Pelto area? What's your guess on how many prospects you have there?

In the 22 area and in the other -- (multiple speakers)?

Yeah. I guess Stone talked about having at least three other fall blocks left to drill. I mean, what would be the timing on those?

Right, right. Ray, this is Roland. You know, we've got maps -- at least another three prospects along the different faults in South Pelto 22. And I think those would be incorporated in the 2004 kind of plans.

I think the immediate plan is to get the number 4 well drilled, and get the platform in and get production established in the block. And then from there on, they'll continue the exploration and test these other structures. They've had -- They were successful in going to the West of the discovery, testing that fault, and now they'll try to go to the east and test some of the other faults that they have mapped.

And then we -- going into this other (ph) block -- we have at least that many type faults there to test also, which is kind of what set up this initial discovery there. So next year, we should have quite a bit of deep shelf type activity just to continue to test these ideas that have seemed to be working this year.

Ray, the one thing -- this quote, this other deep shelf discovery in a block nearby South Pelto. What we tried to do today is we've said that we have found two objectives, that they looked good. We will set protective casing over that, and then we'll drill another thousand feet.

You hate to be too open about what you have until you dig the well and you set pipe on it. And so as we -- trying to portray the well as it is. And it's a little early to be more definitive on that. But from what we've seen, as Roland said, we do expect to drill several more deep wells in that block, and 2004 to test several additional faults that we have identified. So things look good there.

And what kind of production facilities are nearby? Or how long do you think it would take to hook up a discovery?

We probably have some access to some facilities nearby. So we -- that will be a plus for that area that won't require installation of new facilities like 22 does.

That could happen late first quarter, early second quarter. It won't take a year -- which is what the Pelto 22 effectively has taken.

Right. Okay.

Ron Mills, Johnston Rice.

As it relates to the some of this production that you have to come onstream, the 25 million a day, where -- can you give us some sort of direction of where -- what the breakdown of that is by area, and what it looks like in terms of a timeline -- fourth quarter, first, and second quarter?

Yes, I'll let Roland answer that, Ron. But one thing I want to say -- in the last conference call, we said we had 25 to 30 million a day that we thought might be added in the next three quarters. And what we've done, some of those wells have been put online. A lot of them haven't.

And so now, the new current statement is, we think we have got about 25 million a day net production that'll be added in the next three quarters, which takes us to the fourth quarter of this year and the first two quarters of next year. So with that, Roland can go over the specific wells.

All of these are offshore wells. So there's 11 offshore wells. And of course, the one that's the most immediate that's coming online -- maybe even any day now, they are trying to get it turned on -- is at South Timbalier 30. There's three wells there. We drilled two last year. We drilled one this year. The facility is set, and we're just waiting to hear back when they have that on production. But it's any day now. So that's the one that really impacts the fourth quarter.

There's probably a couple of other offshore wells that also come on in the fourth quarter. And then the balance of the big projects is the ones that take us into 2004, including the South Pelto 22. So you know, we're -- I know you're going to ask the question, so -- we are looking at -- from where the third quarter production levels, that you should expect us to be able to show about a 5 percent, maybe up to 7 percent increase in production in the fourth quarter -- mostly dependent on this big platform that's coming online here either today or tomorrow.

And is that going to be average or exit, the --?

No, that's the average (ph) -- we're just talking the quarterly number -- all right, average.

Okay.

And then -- yes, so and we think the prospects look good to give us continued growth in production for the next three quarters, like we said in the release.

Okay. In terms of the 3-D seismic over the Ross and Robin project areas -- when do you expect the delivery of that, and at what point next year do you expect to be able to kick off the drilling in that area again?

Well, internally we were told that in March was kind of the date that we should have receipt of that. And what we said is, why don't we put a June date for drilling of the first well, which would be the first Robin Prospect. So internally, we've said it would be June, July -- would be the beginning of the third quarter next year in our numbers.

And Ron, we will drill two more Ross area wells this year.

Yes, we'll drill the Hamman 3.

-- which I think is the locations belt (ph). And they probably will spud within a week.

And then we'll drill a well west of the Hamman 3.

And is there -- any other wells in the Hamman area or in the Ross area, or -- that you could drill in the first part of next year? Or is really that drilling program going to be on hold until you get the seismic in?

Well, our attitude is that if you look at the tail-end of the existing 3-D seismic, that is kind where we are in the Ross area. And if we can wait until we view that in March, then what hopefully that will do is extend that play (ph) out to the south -- and it'll kind of connect the dots between that well and maybe the Anadarko well that was drilled way south of our Robin prospect. And we can remap all that and save some money, because those are 16,000-foot wells, and the Robin prospect, as you know -- it will be a 19,000-foot well -- it'll be about a $3 million, $3.4 million dry hole.

And our goal is to remap all that. And then if it continues to look good, then instead of having a partner on our Robin Prospect, since we operate it, we own 100 percent of it, we would just keep 100 percent of it when we drill it next year.

Okay. And I guess, Roland, for you, on the 11-1/4 percent notes -- I know they're outstanding (ph), they've been saddling you. I'm assuming the plan is still -- at least assuming that the markets stay the way they are -- that still in May, you're looking to call those notes?

Yes, we see that as a big opportunity to really reduce our overall borrowing costs and just given -- unless the markets change dramatically, that we would take the opportunity. Hopefully it's still there on May 1st, when we have the ability to call them. We don't have the ability now. So that's why they're still out there.

Right. And one cleanup on South Pelto 22, with the facility that's being built right now -- what kind of capacity are you all designing for that facility?

I think initially the capacity for the platform -- what I heard, Ron, was about 150 million a day of gas and about 8,000 barrels of oil. And you can add to that if you need to. Is that what --?

Yes. Exactly. And is that -- have you talk about the cost of that facility?

It's around $8 million -- was my last number, is that -- (multiple speakers)

Right about the time you're all in with $8 million and pipelines and such you're probably -- $10, $12 million.

Okay. 10 million. He said 10 million probably with everything is a good number.

Okay. And would that capacity be sufficient for not just the current discoveries, but even some of those untested fault blocks that you're talking about drilling for next year?

Right.

Rehan Rashid, Friedman Billings Ramsey & Co.

Real quick, maybe some more thoughts on your south Texas program. It seems you -- to be progressive really nicely. Maybe more outlook on Ball Ranch and everything else that's there?

Yes. What we have done there, Rehan, we've -- of course, we've been drilling the Vicksburg Wilcox wells in the Ball Ranch. We've got a big well that we're drilling right now, which is this Wadsworth well. We own a 45 percent interest in that. And the reserve target is about a 60 Bcfe target.

And what you'll see us doing, I think, in '04 -- and I would ask our head of operations what the budget would look like, and we'll probably end up spending about $18 million or so this year in that area. And next year, if we continue to go on the same pace, he would say we'll possibly spend about 25 million next year in south Texas, drilling the similar wells, which is the Vicksburg Wilcox wells, and keep rigs busy all the time in that area.

I think that that area -- you know, a lot of companies are attracted to area right now. There has been a lot of success, mainly because of seismic in that area. There have been a lot of big wells yet. And I think we've got pretty decent acreage position. And we'll continue -- like you said, we will continue to grow that area in '04 and the rest of this year.

Van Levy, CIBC World Markets Corporation.

How are you guys doing?

We're doing great. It's a good, cold day in Dallas, Texas.

A couple of questions. Did you lay out your 2004 budget and production growth targets?

We haven't yet, Van. That's something we'll be working on here by the end of the year.

And would you expect to underspend your cash flow in 2004?

I think that would be our goal is to set a similar budget that underspends our expected cash flow generation. So a lot of it -- we'll kind of look and see where the gas market is, as you get into the winter. I think that -- and then -- that will probably determine how aggressive we are in drilling wells, especially the -- more the development wells.

Okay. Could you give a sense of where your debt is going to be year-end, or debt-to-cap? And then take a leap at year-end 2004 and kind of see where you plan to put it (ph) at that level?

Well, of course, we had a really large paydown in the third quarter. And that's the way our cash flow works, because of paying the interest on the expensive bonds -- paid semi-annually. So the first and third quarter have a lot of extra cash flow compared to the fourth and second.

So we won't be able to pay down 25 million in the fourth quarter at all. It will be a much more modest number -- the combination of both having a lot of drilling going on and the fact that you've got to pay all the interest on the notes. We are expecting some debt paydown, but 5 million to 10 million, at the most. That would get us -- getting really close to that 50 -- I think, you know, it'll probably be like 51 percent debt-to-total-cap -- getting real close to that 50 percent level.

And then let's just take a stab forward one year -- do you hope to be down to 40 percent at the year-end 2004?

You would come up with the same similar type of business plan for next year. I mean -- will took 10 points off of the number 2003, and that would be exactly what we'd like to try to do again next year.

So the notion of deleverage (ph) -- you're going to continue discipline there. Okay.

Yes, because I think the company is -- you know, we see the kind of the average for our peers as being in the mid '40s. And you know, we're not quite to the average yet. So we'd want to be at least at average, if not better. So it's still going to be a goal next year.

Okay. Can we talk about the performance from kind of your key assets -- Double A Wells, maybe some of your recent Gulf of Mexico discoveries? How has the production performance been when you plot your monthly data points against your previous decline curves?

The -- might let Mike over that, but mostly -- you know, it's a -- you know, kind of what we reported on this quarter, you kind of just could see by regions the area that had the big kind of growth in this quarter was the south Texas region. That's from those new wells coming online. And then the southeast Texas region -- and that's the three wells now online at the Hamman area, where you have 35 million a day -- 8H (ph), which we have almost about half of that on a net basis. So that's been the big production drivers onshore.

And the Gulf, a lot of that is coming online. And it's going to drive the increases in the fourth quarter and the first quarter for a lot of these projects that their facilities are being installed. But Mike may comment just kind of overall on the basic asset base.

Well, I think what we see is just continued decline, obviously, where we don't have any development going on. But as Roland said, in the southeast Texas region, what you see there is a big boost in production in the Hamman and Collins wells that kind of offsets somewhat the underlying decline at Double A Wells.

And in the onshore I don't really have anything to add there. We have wells declining, we have wells coming on. So it's -- there's a lot (multiple speakers) of activity and there's a big mix, too.

Obviously, they're going to decline. But relative to your forecasts, are we going see -- can you judge whether you're going to have upper reserve revisions, flat, or downward reserve revisions in any key areas?

Well, obviously, in the southeast Texas, we have upward revisions. We'll have some downward revisions in some areas in the offshore. We typically have had that kind of stuff. You can't always guess right on some of these water drive reservoirs. But I think, overall, in our -- in most of our other areas, we are looking okay.

Okay. And then finally, I'd like -- translating this into DD&A rates, it looks like they've been pretty steady over the year. They dropped in the third quarter. This would suggest that finding cost will be pretty competitive in 2003. Do you have a sense of what kind of range that would be?

Yes, a lot is going to depend on the kind of reserves that get assigned to some of the offshore discoveries, which is kind of early to see what those are going to be. And so those are going to drive our finding cost this year. Because that's -- we haven't made any acquisitions. And they are going to create the qualities added. (multiple speakers)

It's just -- we don't really want to speculate on where those are going to come out yet. You know, the DD&A rates are really a function -- not of changing reserve profiles at this point, because our reserve study has not been done yet, but just of the mix of properties contributing to the production at that quarter. So that -- at a slightly lower DD&A rate in the third quarter was more indicative of some properties probably coming online -- probably south Texas, that had a lower DD&A rate and overall mix. Because as Sessrell Efforts (ph) company, where we are doing that calculation on a field-by-field basis. So there's 50, 60, 70 cough (ph) centers that are all go into that equation. And they all have their own little rates.

Okay. Last question -- I guess a Comstock conference call would not be complete without asking about hedging and whether your views have changed there?

I don't think -- our views haven't changed too much. I mean it is -- we continue to look at hedging and look at -- I think that as we look at next year's capital budget, that might be a reason why we might want to hedge, if we end up -- once we look at our capital budget, if we still (ph) want to spend more, and it's close to the cash flow generated, or there's not the huge cushion, or we want to lock in some debt reduction -- I mean, it's something we were going to consider. We won't hedge for this year. So that the decision was pretty much made.

But we're not going to rule it out -- what we're going to do for next year. We believe it's a valuable tool. When you are trying to drill wells that need a higher gas price, you're going to make acquisitions in this market where you're using higher gas prices, I think hedging is a valuable tool. And we've used it in the past and at the time. But we're not price speculators. So we're not going to tell you that we just think gas is going down. So we're going to make a bet.

What we do need, Van, is that we need to lower our debt-to-cap, though, because over 50 percent over budget is exploration drilling. So we look at that. And we do look at hedging. And I would be disappointed (technical difficulty) if you hadn't asked us that question -- (multiple speakers)

Thanks -- good quarter.

Ray Deacon, First Albany.

I guess, Jay, just a question on the Collins Number 2 well. What new are you fining out on these reservoirs in the Ross area from the wood bond (ph)? Should that be the average rate, I guess, on the next couple of wells you drill, would you expect, or --?

Mike -- What we've found is we found more pay in the Collins 2. We probably found 10 more feet of pay -- maybe 14 more feet of pay in the Collins 2 than the Hamman 1. But it's been tighter. So you remember, we didn't frac (ph) the Hamman 1. It came in natural. Well, we had to frac the Collins 2.

So we're getting good wells -- I mean 5, 5.5 million, 6 million a day for the Collins 2 well. But the Hamman 3 -- Mike, what's your comments on that?

Well, as we try to define the limits of this reservoir, we have found that we found that -- we found best part of the reservoir in the Hamman 1 and the Collins 1. As we move out and somewhat test the limits, we find that we're getting into, as Jay said, thicker and tighter reservoir, which is good. It's just not the excellent quality that we've seen. So what that does is, we think, sets up some pretty good development acreage even in that tighter area.

So what we're seeing is that the porosity varies, the permeability varies. We step out here a well at a time. The Hamman 3 is going to test another limit. And I say that not in a way that we think that we're out there on the edge. We just think that we're probably out of the main channel of great porosity and great permeability.

Really what that will do, Ray, is -- if you parallel the Double A Wells field to kind of the Ross -- when we bought Double A, it was developed on 2-D seismic -- and remember, we drill six wells, we get two dry wells. And then for two years, we participated in that 3-D seismic shoot.

And we came back, and really what most people thought was a drilled-up field. It looked completely different with the 3-D. And we drilled 22 wells and hit 19 of those wells. And the production per well would range from maybe 2 million a day to 14 million a day in the center of the Double A Wells area.

And what we're hoping to do now -- as I'd mentioned earlier -- we really are on the tail-end of that 3-D shoot in the Ross area. If you've seen on a map -- it's the very tail end. And so what we need to do -- that's another reason that we were glad to participate in this seismic shoot over the Robin, because we really needed it for two reasons. We needed it because we have 4,000 to 6,000 acres around the Robin area. But we've got a lot of acreage in Ross. And we need to find out what happens to the south and to the west where we don't really have good coverage. So one thing that's for certain is our technical group will -- if there's value there, I think they're best group out there to uncover it.

Ron Mills, Johnston Rise.

It was answered. Thank you.

(OPERATOR INSTRUCTIONS) Gentlemen, at this time I show no further questions. Do we have any closing remarks?

No. We're -- as a company, and a board and management -- I mean, it's a nice day when you can deliver results that you expected. So we don't always have these quarters or days. So we're thankful for them. Thanks for your presentation in the conference call.

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