Comstock Resources Inc (CRK) 2008 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the fourth quarter, 2008 Comstock Resources earnings conference call. My name is Lemanual and I will be your operator for today. At this time, all participants under a listen-only mode. We will conduct a question-and-answer session towards the end of this conference. (Operator instructions). As a reminder this conference is being recorded for replay purposes. I would now like to turn the call over to your host today, Mr. Jay Allison, President and Chief Executive Officer. Please proceed sir.

Lemanual, thank you for introducing me, and welcome everyone.

I think we should probably have a record crowd today and we will give you all the reports that we have they are current for South Texas, East Texas, the Haynesville, everything. So it should be an excellent meeting. Welcome to the Comstock Resources fourth quarter and annual 2008 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 fourth quarter and annual 2008 results.

I'm Jay Allison, president of Comstock and with me is Roland Burns, our Chief Financial officer and Mack Good, our Chief Operating Officer. During this call, we will review our 2008 fourth quarter and annual financial and operating results, as well as the results of our 2008 drilling program. Our discussions today will include forward-looking statements within the meaning of securities laws, but we believe the expectations and such statements to be reasonable, there can be no assurance that such expectations will prove to be correct.

If you would go to the 2008 highlights, it's on page two of the presentation. We summarize some of the many highlights in 2008. 2008 definitely was a transformational year for Comstock which was recognized by the market as Comstock's share price increased 39% for the year and was the number one performer in the sector. For 2008, we reported revenues of $564 million, and we generated EBITDAX of $459 million in operating cash flow, of $438 million, or $9.64 per share. We generated a record-setting profit in 2008 of $252 million, or $5.53 per share while many of our peers reported massive losses arising from writeoffs. Included in the record-setting profits were gains from the sale of Bois d'Arc Energy, and our sale of non-core properties. Excluding these items and the discontinued operations, we reported reoccurring net income of $147.6 million (sic - see press release) or $3.25 per share. The strong financial results in 2008 were driven by 32% production growth in strong oil and natural gas prices in the first three quarters of the year.

The production growth is primarily coming from our successful drilling activities in 2008. 132 of the 136 total wells that we drilled were successful. We funded our $426 million in capital expenditures exclusively out of operating cash flow in 2008. This activity added 102bcfe to our proof reserve base, $116 million of our expenditures have been invested to increase our leasehold in the emerging Haynesville Shale play. Our proved reserves were negatively impacted by the fall in oil and gas prices, which caused 52bcfe in downward revisions. Excluding the downward revisions and the spending on unevaluated leases in the Haynesville Shale, we had a finding cost of $3.03 per mcfe in 2008.

In hindsight, our best move this year was to complete the divestiture of our offshore operations, and a $138 million in non-core properties prior to the onset of two hurricanes, the substantial decline in oil and gas prices, and the current credit crisis that we are experiencing. We are now positioned with a very strong balance sheet that will allow us to develop and prove up our Haynesville Shale acreage this year.

I will turn it it over to Roland to review the financial results in more detail. Roland?

Thanks, Jay.

Strong production growth is one of the major factors contributing to our record financial results of 2008 as shown on slide three in the presentation. In the fourth quarter, our production averaged 164 million cubic feet of natural gas equivalent per day, 23% higher than our production in the fourth quarter of 2007, of 133 million per day. For all of 2008, our production of 59.9 bcfe was 32% higher than production in 2007. Pro forma production, excluding the properties we sold was 58.2 bcfe, a 40% increase over pro forma production in 2007. Our East Texas north Louisiana region averaged 91million per day in the fourth quarter which is 34% higher than fourth quarter of last year. Production in South Texas was up 56% to 56 million per day, as compared to 36 million per day in 2007.

In production in other regions was 17 million per day, down slightly from the 19 million per day we averaged in 2007's fourth quarter. Production growth slowed in the fourth quarter as we were transitioning to drilling horizontal Haynesville wells and away from drilling conventional Cotton Valley wells which have provided much of the production growth that we had in prior quarters. The Haynesville wells take much longer to drill and complete.

Given this fact, we expect production in 2009 to fall in a range of 62 bcfe to 67 bcfe for 7% to 15% higher than pro forma production in 2008. Production is expected to be flat in the first quarter of this year, with production growth resuming in the second quarter when our recent discoveries in South Texas enter the Haynesville wells begin to make a contribution to our production rate.

The fourth quarter saw a rapid decline in oil prices as we cover on slide four in the presentation. Our average oil price decreased 31% in the fourth quarter of 2008, to $52.16 per barrel, as compared to $76.10 per barrel in the fourth quarter of 2007. Oil price in the fourth quarter averaged 89% of the average NYMEX WTI price in the quarter, which was consistent with our average realizations last year. For all of 2008, our realized oil price is $87.15, and was 43% higher than our oil price of $60.96 in 2007. Our average 2008 oil price was 88% of the average NYMEX WTI price.

Slide five shows our average gas price, which is also declined significantly in the fourth quarter. Our average gas price decreased 10% in the fourth quarter to $6.44 per mcf as compared to $7.15 per mcf in the fourth quarter of 2007. Our realized gas price was only 93% of the average Henry Hub NYMEX price in the fourth quarter, reflecting the wide differentials that began in September after the hurricanes and also in combination with weaker natural gas liquids prices. We did have 11% of our gas production hedged in the fourth quarter which increased our realized gas price in the quarter by $0.19 per mcf. For all of 2008, our average gas price increased 28% to $8.83 per mcf as compared to $6.89 per mcf in 2007. Our realized gas price was 98% of the average Henry Hub NYMEX price in 2008, and going forward into 2009, we will have approximately 10% of our gas production hedged at $8.20 per mcf.

On slide six, we outline our oil and gas sales. Our sales from our continuing onshore operations increased 5% to $100 million in the fourth quarter as the higher production level offset the declining oil and gas prices. For all of 2008, oil and gas sales increased 70% to $564 million as compared to $332 million for 2007. The increased sales relates to the 32% higher production level we had, combined with strong oil and gas prices.

Our earnings before interest, taxes, depreciation, amortization and exploration expense, and other non-cash expenses or EBITDAX from our continuing onshore operations was comparable to 2007's fourth quarter's EBITDAX at $72 million, as shown on slide seven. For the full year 2008, our EBITDAX increased 83% to $459 million as compared to $251 million in 2007.

Slide eight covers our operating cash flow. Our cash flow just from our continuing onshore operations increased 26% in the fourth quarter, to $80 million as compared to cash flow of $63 million in 2007's fourth quarter. Operating cash flow in the fourth quarter of 2008 benefited from a reduction in our current income tax provision, which resulted for the lower income we had in the quarter plus the ability that we had to use carry forwards and expense more intangible drilling costs due to the very large gain we recognized on the sale of Bois d'Arc, which is reflected in discontinued operations. For the full year 2008, our operating cash flow was $438 million, 103% higher than cash flow in 2007, of $216 million.

On slide nine, we outline our earnings. We reported a net income of $252 million, or $5.53 per diluted share for 2008, which is by far the highest annual profit in our corporate history. If you exclude the gains recognized from the sale of Bois d'Arc and the other properties we sold in 2008, and the discontinued operations of Bois d'Arc and the impairments that were recorded in the third quarter. We reported recurring net income of $148 million or $3.25 per share for 2008. For the fourth quarter we reported a loss of $96 million, which is caused by an impairment charge recorded to reduce the carrying value of our investment in Stone Energy from $40 per share, where we valued it at closing in August to $19.19 per share, where we valued it at the end of the year. Excluding the impairments taken in the fourth quarter, our net income would have been $10 million, or $0.22 per share.

We outlined our cost structure on slide 10. Our lifting costs in the fourth quarter averaged $1.37 per mcfe produced as compared to $1.32 in the fourth quarter of 2007. The decrease in the approved reserve base at the end of 2008 resulting from the lower oil and gas prices has increased our DD & A rate to $3.38 per mcfe as compared to $2.81 per mcfe in 2007's fourth quarter.

In slide 11, we outlined our production costs for the full year. Our lifting costs averaged $1.45 per mcfe in 2008, up slightly from the $1.43 we averaged in 2007. Our DD & A per mcfe produced increased to $3.03 per mcfe in 2008 as compared to $2.76 per mcfe in 2007.

Slide 12, as we outline our capital structure at the end of 2008. We had $210 million in total debt at the end of the year. In the fourth quarter, we borrowed $35 million under our [bank] credit facility, which has a $590 million borrowing base. We borrowed these funds and used the substantial cash balances we had on hand, mainly to make the tax payment that was due from the gain on Bois d'Arc that was due on December 15th. We ended the year with equity of about $1.1 billion. So our percentage of debt to our total book capitalization was 17% at the end of the year which was a substantial improvement from the 50% level, where it stood at the end of 2007. We ended the year of 2008, with a very strong balance sheet, and the Company is now very well positioned in this period of tight credit with $555 million undrawn on the credit facility.

On slide 13, we detail our drilling expenditures for 2008. We spent $426 million in 2008 for our drilling program as compared to $335 million that was spent in 2007. $333 million of the dollars were spent at our East Texas, North Louisiana region, $85 million was in South Texas and $8 million was spent on our other regions. $116 million of the $426 million spent was spent to acquire unevaluated leasehold in the Haynesville Shale play. I will now turn it back over to Jay.

We've got several more slides and then we'll open it up for question and answer.

If you go to slide 14, we have a slide on our pre-reserves on page 14 of our pre-reserves at the end of the 2008 were estimated at 582 bcfe, compared to the 651 bcfe of reserves related to our continuing operations at the end of 2007. Our reserves are 90% natural gas and 67% are proved develop. We operate 85% of the pre-reserve base. The present value, using a 10% discounted rate of the future net cash flows before income taxes of the reserves at the end of 2008 is approximately $820 million, using year-end December 31st, 2008, oil and natural gas prices of $34.49 per barrel for oil and $5.33 per mcfe for natural gas. We produce 60 bcfe of reserves in 2008 and divested 59 bcfe in 2008 of pre-reserved relating to certain non-core properties. The pre-reserves were negatively impacted by downward revisions of 52 bcfe.

Those revisions were primarily the result of the lower crude oil and natural gas prices used at December 31st of 2008 to determine whether the production or development of future reserves would be economic. Using 12 month average prices as of the first day of each month for crude oil and natural gas prices realized by the Company in 2008, of $78.09 per barrel and $8.32 per mcf our proved reserves would increase to 617 bcfe with a PV10 value of $1.8 billion. We spent $426 million in 2008 on onshore acquisitions, exploration and development activities, which added 102 bcfe to our proved reserve base resulting in a finding cost of $4.16 per mcfe if you exclude the downward revisions. If you exclude the $116 million that we spent on unevaluated leases in 2008, the finding cost improves to $3.03.

On slide 15, we focus on our East Texas, North Louisiana region. We drilled 115 wells in this region to 12 different fields in 2008. All but one of these were successful. Many of these wells were horizontal well. We have tested these wells at a per well rate that averaged 2.8 million cubic feet equivalent per day, a substantial improvement from our average rate in 2007 of 1.4 million cubic feet equivalent per day. The prolific wells at Hico Knowles and Taylor Cotton Valley and Haynesville horizontal wells account for the improved per well results. The horizontal wells averaged eight million cubic feet equivalent per day and the vertical wells averaged 2.4 million cubic feet equivalent per day. Many of the vertical wells were drilled in the Logansport and Hico Knowles / Terryville area in North Louisiana. We drilled 37 wells in the Hico Knowles / Terryville area. All of these wells have been completed and had initial production rates which average 3.5 million cubic feet equivalent per day. We drilled 45 wells at Logansport field, 41 of these wells have been completed with initial production rates which average 2.1 million cubic feet equivalent per day.

If you would turn to the Haynesville Shale play slide which is slide 16, we outline our holding in the emerging Haynesville Shale play in North Louisiana and East Texas. Our acreage is highlighted in green. We currently have 86,032 gross acres and 70,504 net acres that we believe are perspective for Haynesville development. Given expected well spacing of 80 acres and an expected well recovery rate of five bcfe per well, our acreage could have 3.3 tcfe of reserve pont with two producing horizontal wells and are in the process of completing three more. I will have Mack Good our Chief Operating Officer go over these wells. Mack?

Thanks, Jay. As everyone can see on slide 17, we have a map showing our current activity in the emerging Haynesville shale play. We completed two horizontal wells and have eight additional Haynesville wells in progress. The BSMC 7 1H well in the Toledo Bend north field was successfully completed in December of last year, with an initial production rate of approximately nine million a day. We have an 88% working interest in this well.

We have a 22% interest in El Paso's successful Gamble 24 H which was recently completed with an initial production rate approaching 14 million a day. We are currently completing three additional Haynesville horizontal wells. We operate all of those wells.

Our second operated horizontal Haynesville well, Collins 15 1H in the Logansport field. This was drilled to a total depth of approximately 11,350 feet and has a 4200-foot lateral. This well's completion has been delayed due to mechanical problems. We are completing the Bogue A6 well in the Waskom field. This well reached an 11,400-foot vertical depth with a targeted 4000-foot lateral extension. We are completing the Hart 1H in the Logansport field which reached 11,500-foot vertical depth and it has a 4,000-foot horizontal lateral.

We have five Haynesville horizontal wells drilling. The Green 13 H in the Blocker field has reached an approximate vertical depth of 11,650 feet and we are currently drilling ahead this well's horizontal 3700-foot lateral. The Headrick 1 H, in Bethany Longstreet field reached a vertical depth of 11,850 feet and we are currently drilling the 4,000-foot lateral on this well. The Holmes number 1H in Logansport is currently drilling at a vertical depth of approximately 11,000 feet, and we'll drill a few hundred more feet and kick the well off and drill an approximate 4,000-foot lateral in that well.

We are also drilling the Moneyham 7 H and Longwood field and this well is currently drilling at a vertical depth approaching 11,000 feet. We also just finished drilling the vertical section to 11,730 feet, in the BSMC LA 12 H well in the Toledo Bend north field, and this well is waiting on the spud of its horizontal section.

I will turn it back to Jay.

I'm sure in a moment that you will all have questions that will be addressed to Mack on this slide 17 and we will pull this back and go over it again in a moment.

I would like to continue the presentation and go to tab 18. Our South Texas region is displayed on slide 18, and our south Texas region we drilled 15 successful wells in 2008, and we had three dry holes. 14 of these wells have been tested at a per well average rate of 3.3 million cubic feet equivalent per day. Four of the successful wells are in the Las Hermanitas field Duval County, Texas. Six were in the Javelina field in Hidalgo County and three were in the Ball Ranch field and one was in the Lorenz Ranch field. The most significant discovery in this region is the Leyendecker 10, drilled in the Fandango field.

On slide 19, we have a map of our Fandango field. We are completing the Leyendecker 10 well in the Fandango field. We have a 100% interest in this 16,200-foot well and are currently finishing this well's multiple stage completion. We have two wells offsetting this successful exploration well. We are currently drilling the Trevino number three to a planned vertical depth of 14,900 feet and recently drilled the Muzza number 13 to a 16,300-foot vertical depth. Both of these wells appeared to have Encountered the target Wilcox sands and are expected to be successful. We will have some more comments on those in a moment. If you would turn to the 2009 drilling program, we just have 20.

We are announced today that we are reducing the 2009 capital budget from $450 million to $366 million, in response to weak natural gas prices. The revised budget which is outlined on slide 20 is Comstock drilling approximately 41 wells this year, or 34.8 net wells. The drilling program will continue to be focused on our higher return opportunities, including our extensive acreage position in the Haynesville Shale. The East Texas, North Louisiana operating region accounts for the largest portion of the revised 2009 budget. We forecasted expenditures of $319 million. We now plan to drill 36 wells in this region or 31.4 net wells in 2009, which includes 30 Haynesville shale horizontal wells or 25.8 net Haynesville shale wells and two Cotton Valley horizontal wells. We expect to spend $47 million in our South Texas region to drill five wells in 2009.

On slide 21, we display where we plan to drill the 30 horizontal Haynesville wells. This is important; we expect to have an average of 86% working interest in these wells. We plan to drill these wells with the goal of proving up as much of our acreage as possible instead of just drilling in one area to maximize current production. We think this program has a potential to provide us with substantial reserve growth in 2009.

On the 2009 outlook, to slide 22, in looking ahead to this current year, we feel that Comstock is very well positioned to continue to grow and add value to our stockholders, even in the challenging environment that we all live in now. The divestitures of our stake in Bois D'Arc Energy, and the non-core properties that we've completed provided us an extremely strong balance sheet which will allow to us aggressively support the continued growth of our onshore operations which is increasingly important, given the tight credit market that we are in today. We are well positioned for future growth with a large inventory of drilling locations in the Cotton Valley and the Haynesville shale in East Texas and North Louisiana and in the Vicksburg and Wilcox trend in South Texas. We have reduced our drilling program to $366 million in order to maintain our financial flexibility. We plan on only drilling our highest return projects this year, which primarily focuses on the Haynesville shale. Our primary goal in 2009 is to prove up a portion of the 3.3 tcfe of reserve potential that our position in the emerging Haynesville shale play exposes us to. I'd like to turn it back over to Lemanuel and we'll open it up for questions.

(Operator instructions). Our first question comes from with Kim Pecanovsky with [Collin Stuart]. Please proceed.

Can you give us some details on the El Paso well? The number of stages, the choke, etc.?

It was drilled to 16,100-foot measured depth with an approximately 4,000-foot lateral. It was stimulated in 10 separate stages and it flowed 14 million a day with a little over 4,000 pounds flowing casing pressure on the initial test. And our report as of yesterday, it's continuing to flow at plus 8 million pounds a day rate.

Okay. And you just have a tiny bit of acreage in that region; is that correct?

Actually, no.

Oh, that's -- okay, that's in Bethany Longstreet.

Right.

What is your acreage there?

In Bethany Longstreet we have at least three sections of Haynesville.

Okay. And what's your total acreage at Logansport and total acreage in deSoto Parish?

DeSoto Parish, we are at over 30,000 net acreages, well over 30,000 and Logansport is probably around 3,000 acres, Kim.

And am I correct that your well, the Collins well in Logansport will be the first completion in that field in the Haynesville?

Yes. On a horizontal well.

Yes, on a horizontal well.

Yes.

Okay. Great. And -- let's see. The two wells in the budget for South Texas. Are they the two wells that Linedecker is drilling now, were those wells spud after year end.

It's the Musa 13 and the Trevino 3. They were spud light in Y '08 and early '09 and so it's carry over money for those wells and we also have a couple of wells in the budget for our assets in Kennedy County.

Okay. And a couple of questions on the numbers. Thank you, Mack. Roland, how do you determine the amount of interest you will capitalize and what should we expect -- what should we be considering in our models going forward for '09?

Yes, the interest that we capitalize is on our unevaluated properties and so even though we always capitalized, it's not a very significant amount in the past, so it hasn't been noticed, but since this quarter, we have a fairly large balance in the unevaluated properties which is mainly all the Haynesville leases and we had such low interest expense, obviously it's a much bigger component. So it would be a -- we capitalized $1.7 million in the fourth quarter in interest and it probably will be a similar number in the next couple of quarters until we evaluate that acreage and move that into properties.

Okay. But is it -- are you -- and I don't have an accounting background, so this may be a dumb question, but are you forced to capitalize that or is it your choice to capitalized?

No, whatever you have property -- whenever you have something that's unevaluated and it's active, you -- you capitalize interest. So we have always capitalized interest on it --

I saw in 2007, you really didn't have anything capitalized.

Right. We had so little acreage.

And a little bit in '08.

Yes.

Okay. All right. And just a question on the differentials. I mean, I don't know if you project going forward. They still stink right now. What are you looking at for the future and is there any thought on hedging, basis differentials or does that go into your anti-hedging policy?

Well, we -- when we do hedges, we always do them with a basis.

With a basis.

That it's not going to be a hedge. So the hedge we have is at Houston ship channel for that South Texas gas, because that ties into where that gas is sold. So we always hedge bases when we do a hedge. But as far as -- yes, I think what's happened is the different markets, the different trading hubs, there's less liquidity that's available in those areas and that's contributing to the water differentials, the lack of liquidity in those trading values compared to what you had in the past.

In East Texas, do you expect that differential to widen as a lot of the Haynesville production comes online and there's obviously the -- the local demand with industrial demand being down so much stinks so -- do you think it will get worse before it gets better on the differentials.

It actually improved late December, we saw Houston ship channel tighten up some. So it's hard to project what will happen in the different regions. But I think, you know, obviously the transportation costs in North Louisiana will be higher, as it's more competitive to get into the -- in the different markets and sometimes that cost we reflect in lifting costs and sometimes it's in the differential depending on kind of where the title of the gas is taken.

Okay. And Mack, have you had any mechanical issues on the Bogue well or the -- what is it the Hart that's being completed now?

No. We have had no issues on either of those wells.

Okay. And when do you guys -- what's the current situation now with the Collins well and when might we expect you guys to say something about these three wells that are completing?

Well, the -- the Collins well, the mechanical issues were caused by failure of surface equipment during a frac job and we had to make several repairs to the well bore integrity and now we are cleaning out the well bore there's an obstruction that we are trying to remove and so in a few weeks we should have the well hopefully back to a status where we can complete the well bore. And with regard to the other two wells, the Bogue is about three-fourth's complete. We have a couple of stages to go, and the Hart, we are just rigging up for the first stage on that well.

Okay. All right. So it's going to be a while.

Yes.

A little while.

Right.

Okay. Let's see. I have one more question. Oh, and then I will leave it to someone else. Any plans to do mid-year reserve report this year, being that you are going to have all of this Haynesville activity?

Well, we have an internal review every quarter here at Comstock. And we're certainly going to go through that process and have that for internal assessment.

Okay. But no outside reports?

Hadn't planned one, no.

Okay. Great. Thanks a lot, guys.

You're welcome.

Thank you.

Our next question will come from the line of [Ray Deacon with Pritchard Capital]. Please proceed.

Yes, I guess a question for Mack. What do you think of -- what do you think about the Comstock announcement on transportation and does that allow you to kind of breathe a sigh of relief? And maybe one other question about proppant and what you expect to use resin coated or ceramic proppant and what seems to be working based on the two wells that you've got, do you have enough data to still feel confident about 5 bcf for the Haynesville horizontal?

Can I get a little clarification on the transportation?

Yes, just -- well the Chesapeake announcement that they are going to be building up a large increase in take away capacity, I think the announced 1.2 bcf per day. In any of the areas you are in, does -- do you see any bottlenecks and how are you handling that, I guess?

Certainly. I mean, we -- we're pleased by any improvement when we hear of any improvement in the take away capacity in the Haynesville for obvious reasons. The -- the VP of marking here at Comstock has been working diligently on acquiring the firm capacity that we think we will need. We have some relationships that I can't give you details on, but we feel comfortable in the relationships that we have that we think will be able to provide the firm as we build rate.

With regard to the profit question that you had, we've been keeping very close tabs on what other operators are doing with not just the proppant selection but the types of jobs are that being pumped. We are sharing jobs with other operators and we are very interested in the resin coated selection of the proppant and we think that can yield some real dividends -- especially in cost savings. What was the third question.

It sounds like you are pretty confident about the 5 bcf number.

Yes, we are very confident that it's strongly supportive of all the data we have. As you know, we have been fairly conservative throughout this forecast and forecasting the Haynesville. And we think, as the data accumulates, that perhaps we can move that [type] curve north, but right now, we're staying with our five because we think that's a conservative estimate.

Great. Thanks very much.

Yes, sir.

You know what we did Ray, and if you go back several things, if you read the -- everybody has the Wall Street Journal. You look at the front page of "Wall Street Journal," and the highlights are -- "I was young." "I was stupid." "I was naive." I think that can apply to the energy business too.

I think what we tried to do in giving you that 5 bcfe's in the UR, I mean, we learned 10 years ago when we bought Bois d'Arc in '07, when oil went from $35 to $9 in April -- this is in '97. In '98, oil went from $35 down to $10 a barrel and we didn't have long-term debt. We had all kinds of problems. And we learned this cycle that we needed to divest ourselves of a bunch of things and we learned that 10 years ago. We also learned that when we ramped up the Cotton Valley program, that to drill 50 wells or 100 wells was almost impossible to do with the manpower that we had. So we -- we've tried to be conservative on the numbers that we've given out.

Now, we've -- we missed a few of them, but we initially came out with 4 bcfe and as of December, really January of this year, we said, well, we think, it's 5 bcfe and I no we did marketing trip on the East Coast the second week of January. So, people would say, why are you comfortable with 5 bcfe now as an EUR. We said, well, there's a lot of additional data out there, and we believe it and we have our own data. So when we give you those numbers, we -- hopefully we are on the bottom end of aggressiveness and we're accurate. So, hopefully, we will move that number from, 5 to 6 bcfe, but we are not there yet.

Got it. Thanks.

Our next question will come from the line of Ron Mills with Johnson Rice. Please proceed.

Hey, guys. A couple of questions. Mack, can you give us an update on the bsmc number 7, the first well you brought on in December. I think you walked through where the gamble is currently, just curious as to how the -- the bsmc 7 is holding up.

Sure, the first 30 days averaged north of 6 million a day. That's above our 5 bcfe type curve so we are pleased with profile. It's producing more than 5 million a day. The pressure decline has stabilized and is sitting there making 5 million a day and has for the last two to three weeks. So we're very pleased with the well's performance.

Okay. And just to -- to expound a little bit on one of Kim's question. From pricing situation in East Texas and North Louisiana, what's the best pricing point to look at? I know a lot of people, particularly on Haynesville are looking towards Perryville, but I know there are back fall options to carthage. Going forward, maybe it's for you, Mack or the marketing guy. What should we expect to look for in terms of pricing up?

Well, I personally like all the options. I wouldn't take anything off of the table as far as moving the gas out of the Haynesville and certainly all of the operators that have substantial acreage positions and a -- a reasonable drilling program this year would agree. And so we want that additional capacity and as a previous individual mentioned, Chesapeake has announced they are installing some additional capacity.

There's a couple of other rumored installations, again, that we've had some conversations with some folks about, and as all the operators are doing, we are looking at laying our own pipes to facilitate the transport of our gas. So -- but back to your original question, I would certainly keep all the options on the table.

Okay. And in addition to energy transfer line, where Chesapeake is the lead supplier and I know Regency has been out talking about their Haynesville line, have you locked up any firm transport at this time?

We do. We do have some firm locked up, yes, sir. And it was time we think it's sufficient for the near term.

And is near term 2009 or --

Yes. That's -- that's our intention.

Okay. And then lastly, in South Texas, towns like both Musa and the Trevino have encountered pay. Obviously Trevino is not being drilled as deep. Should we take that to mean that it -- it's not necessarily targeting the same three zones that the Linedecker encountered and is the Musa also targeting -- I was trying to get a an idea of what to look for.

Sure, the Musa has been logged and we will complete that well in the near term. The Trevino, we are continuing to drill the well to improve our structural position. And those two wells did hit some of the same reservoirs as the Linedecker. And we're quite pleased so far with what we've seen.

And the status of the Linedecker, the Linedecker is being completed as you would certainly expect from the bottom up. We've had had a couple of test zones that we wanted to evaluate for obvious reasons. It bears on future work in the field. So the completion is taking longer than it would otherwise. We're currently at the top of what we call the T6, the Wilcox reservoir, and we are evaluating that -- that zone, and we hope to frac that zone sometime next week.

And is that expected to be -- was that expected to be the initial producer?

We'll probably commingle that zone with another package of reservoir sands of the whole. So it will -- it will probably be another three to four weeks before we get the well buckled up and flowing to sales.

And how shortly after that should we -- should -- would you expect to follow with the Musa and the Trevino?

The Musa is probably going to be right on the heels of the Linedecker. The Trevino, I'm a little uncertain just because of the directional work that we are doing and getting the logistics scheduled for that one. So I have to remain vague on the Trevino.

Thank you, guys.

Ron, the other thing with the -- you and Ray and Kim, if you look at reserve adds which is the focus of '09, I mean the Musa and the Trevino, we didn't add any reserves in '08 for those wells. And as Mack said, we did encounter the Wilcox sand. We expect the Linedecker well to be a big well and Mack kind of gave you a time frame on that.

You weren't able to book much on Linedecker at line end, because you don't have any production, right?

Right.

And I think even if you go to Haynesville, we booked maybe 10 bcfe in all of the Haynesville because we only had our well and the El Paso well. If you look at the future of '09 in reserve adds it hopefully will be substantial. We did not book many Haynesville reserves in '08.

Were you able to -- I think people talked about booking a couple of puds for producing. Were you able at least in the PSMC 7 well to book a couple of offsets?

Yes, sir. That's the only well we were able to evaluate in time to do that with.

Yes, that's -- again, it's around 10 bcfe in the Haynesville, so the beauty of '09, really, we have already ramped up the drilling program that should result in hopefully material reserve adds for the 30 Haynesville horizontal wells and then you can add the two Cotton Valley Taylor wells and then the well that you were talking here, the two deeper Wilcox wells in South Texas. So you know, the gross should come without having to issue expensive equity or expensive senior notes.

We should be able to maintain our strong balance sheet through this down cycle and grow the reserve base at the drill bit and, again, all of this is possible because in '08, we were just so fortunate to complete the divestiture of our onshore properties and to sell the non-core assets and we did all of that prior to the hurricanes and declining oil and gas prices and being of course, before the current credit crisis that we are in. I don't think we've ever been better positioned to grow than we are today; a lot of that will be the next three quarters will be the reporting from Mack on how we're doing in the Haynesville.

Since you brought up the balance sheet, and y'all avoided the early acquisition market last year, and cleaned up your balance sheet. You know, there's been a lot of questions about the A & D market out there, given the credit problems that you just referenced. Are you seeing the A & D market heat up a little bit or at least have an increased number of opportunities that your balance sheet can --

No. Ron, the way we look at that. Our business model in '09 is not to acquire anybody or anything, or any material acquisition. It's to add to the Haynesville. We have been doing that on a monthly basis. It's to -- you know, it's to figure out how to complete the Haynesville wells without being delayed a month or two, which we have been delayed. So we have to get over that learning curve. And we have said in all the meetings that we've had this year, that we don't see this credit crisis going away in the blink of an eye. It's going to be here a little while. So our $590 million availability, we put a marker in the sand and said, we want to maintain at least half of that, period. We would not want to use our credit line and have less than $300 million or $350 million of availability left. We want that amount unused. So if we were to go out and find something we just fell in love with, that we needed to own, we would not lever this company up. We would issue shares to do that. And you know that we're very stingy on that. I think the last time we issued equity was maybe in '03, and even when the stock was $90 last year, we didn't think the right thing to do was to issue equity. We think that you have to have two things. You have to have a healthy company, which we have, and you have as a stockholder, but the other thing, you have to grow the stock price for the shareholders. And typically you don't do that by issuing a bunch of equity or incurring a lot of expensive debt. Do you that by developing your core area and I think that's the -- we hopefully will have a 7% to 10% production increase this year. Maybe more; we don't know. We have to see how the Haynesville performs. We could have some material reserve adds. That's our total goal this year is to keep five to seven rigs going in the Haynesville. We will see where commodity prices end up and really, really grow the reserves.

I think that's where Kim came in with that question, would you do a reserve report? Well, I don't know. We typically never do. But we do plan on adding some material reserves. I think that's a great growth program for the market that we are in and, no, we have not seen any properties out there or companies that -- that are worth buying. Those are that are for sale typically have a reason to be sold and we have avoided those.

All right. Thanks guys.

And our next question will come from the line of Jack Aydin with KeyBanc Capital Markets. Please proceed.

Hi, guys.

Hi, Jack.

Most of the questions I asked. This is directed to Mack. The Collins well, the Linedecker well, they both delayed. Is it the -- whose -- who is at fault? Is it people? The service companies that you are using? Or what's holding them up so much?

Well, I will take the Linedecker first. The Linedecker is delayed just simply because we encountered some sands at the bottom of the hole that he with wanted to test. In order to get some data, that we thought would be important in the continued development of Fandango. And so it's no one's fault. You can blame me. I made the decision to do that. Just because it's in the best interests of everyone to get that information.

With regard to the Collins, what happened the devil is always in the details no matter what business you are in. -- no matter what business you are in. The Collins completion, we had some surface equipment that as we mentioned earlier, that failed during the frac operation. And that particular piece of equipment is equipment that is rented by every operator, from vendors in the oil and gas industry that supply that sort of equipment and we have used this particular vendor many, many times. We have never had a problem except for this particular instance. And so certainly we're working with that vendor to insure that this doesn't happen again, that the appropriate steps are taken to minimize the possibility of that occurrence. We were thankful, very thankful that no one was hurt when that piece of equipment failed. I mean, you have to understand.

I know most of the listeners were not on the job that involves the massive hydraulic fracturing operation, especially in the Haynesville. But it is very high pressure and high rate work, and safety is number one on jobs like that, so we're taking the appropriate steps, but, no, I wouldn't -- I wouldn't say that it's anyone's fault. Things sometimes break in the real world, as you know. So we're taking the necessary steps, as I mentioned earlier, to insure that that is not likely to ever happen again.

But, Jack, you know, you had heard that we lost the well, it was a dry hole, all that garbage. No. We had a well head blow off and nobody knew that would happen and then we had some fishing tools hung in the hole and we're fishing them out. So, you know, did we disapprove the Haynesville in that area, no. We've had a problem on a well and it's taken probably another six weeks longer than we thought or maybe two months. That's what you get for highlighting one well. That's why we've tried not to do that, but I know it's part of the dance right now.

And every well is important, but we did have problems. We had problems on the first well, the Toledo Bend north well. We had five stage frac, and the service company moved off and moved back. We had the final five stages. We had a $9 million a day well. Would it have been better to have 10 stages at one time, absolutely. Is that our goal? Absolutely. Is that what we've hired Slumber J to do? Absolutely.

So I think, again, if you just look at this momentum and you look -- if you look at the chart on that slide 17, we tried to outline what we're doing, what is important, and we're going to be doing a lot more of the same thing with the same people and hopefully it will be a lot more predicable. Believe me, we wanted to deliver the news of the Collins and the Linedecker, but it is what it is and you have to trust that we're going to get better at it. And I think we will.

I'm sure you will. How much of reserve from -- of the reserve you booked from the Linedecker?

We were able to -- we booked 13 -- about 13 bcfe net to the revenue interest for the Linedecker discovery.

Okay.

It's a pretty substantial discovery.

Yes.

Well, we told you, we thought it was a really good well and that's why we drilled a well to the north and south of it, which were in two different fault blocks. So that's -- that's all -- again, the wells that we drilled this year, the 40 some odd wells, if they are successful, those will add new reserves. You won't convert puds into PDP, you add new reserves and I think you add them in our core area and you add them with the people who created wealth for the Company and you do it with a strong balance sheet and you keep your strong balance sheet. And maybe that's where you come in mid-year and you have added a lot of reserves and your borrowing base is even better, but I don't know. We are going to keep all of our strength around us.

Back to Kim's comment, would you -- would you elect to do some operational updates in the middle of the quarter since you have a couple of wells that are in the process of completing and fracking and everything, Jay?

You know, Jack, it's funny. I read everybody's update because I respect all the analysts and I read -- I read one report -- and I won't name his name -- Ron Mills -- and he said in four to six weeks, that you know, we would maybe give an update. You know, Jack, I think that if it's -- if it's so important that you know and we have a couple of wells that are completed, go or bad, doesn't matter, but we know they are absolutely completed and we are finished with them and they are producing what they are going to produce, whether it be the Linedecker or the Collins or the Bogue, then what we normally do is, Mack and Roland and I will get together to see what type of pressure we have from the outside world and then we'll say, okay. We try to do it on a quarterly basis. Maybe we don't make it to the next quarter. Maybe we have to do something in six weeks this time. And then try to get everybody to this quarterly basis. So I -- I don't know. You could probably bend our arm enough and we might do something.

We can't have this Collins deal like an overhang for forever and ever and ever. We need to get a systematic approach to information. Some of the other companies, Jack, they are drilling and completing five and ten wells at a time. And when you get to that stage, you know, you are given a lot of information. I just hate to give it out on one or two wells all the time. But, you know, we are going to listen to everybody. And we think it's material, then we'll have a duty to put something out.

So -- once you get rid of the Collins.

We will be fair and do the right thing; if we don't, then slap us around.

Yes. Thanks a lot. I appreciate it it.

And our next question will come from the line of [Dan McSpirit] with BMO Capital Markets. Please proceed.

Thank you and good morning, gentlemen.

Hi, Dan.

You know, of the Haynesville Shale horizontals that you will drill in 2009, how many of those will test or verify 80-acre spacing?

That's a good question. We're drilling in a -- as you know, a wide area, as Jay mentioned earlier in the presentation. So I can't -- I can't give that to you, Dan. I can get back to you on that.

Okay.

You know, we are testing 8 or 9 different areas so proving up the 80-acre spacing isn't the initial goal.

Got it. Got it. Okay. And then --

We can, though, get back with you on that.

Okay.

That's a great question. It's eight different areas for the 30 wells. Again, it's 30 gross wells, but it is almost 26 net wells. So it's a lot of ownership in those wells.

Dan, you can see on the breakout, I think it is slide 30.

Right.

You can see where we are drilling, and certainly like in Logansport, and Toledo Bend north, there may be some prove up, but I know Toledo Bend north is about a 20,000-acre package. So there's a lot of room there to drill.

Yep. Understand. Understand. And another question here, will the wells currently drilling in those that are planned throughout 2009, will they be completed any differently from what's been done thus far and, if so, how?

Well, that's another good question. And the short answer is yes, because we're -- we're changing already, and as I mentioned earlier, we're trading data with various other operators. We're -- the land grab part of the Haynesville play is over, and now everyone is -- has pretty much agreed to share information on a confidential basis and so we have several agreements in place to do that. And as a consequence, we are -- we are all learning what not to do is as important as learning what to do. So we certainly will change our frac designs up and our completion approach. Yes, sir.

And working, Dan, with -- well, I will let Mack go over who we are working it with. We are working with the people who do it the best.

We are working with several groups. And since it's confidential, I'm not going to name names here, but we -- we've learned a lot and I think they have too through the exchanges of data and as far as how we are changing certainly there's a move towards going with certain perforation phasing, certain clustering of the perfs in order to properly fracture the targeted stage or thinning of the fluids. We are changing the proppants. We are changing the concentrations that we are pumping. So there's a number of things that are being changed.

Okay. Got it. Got it. And then lastly your original budget of $450 million was announced at the beginning of January, and so here in four short weeks, you have cut it by close to 20%. You know, what price or prices in the future strip do you have to see to revisit that number of $450 million? And if you did revisit that, would it all go to the Haynesville?

Yeah, Dan, this is Roland. I think really what -- of course, our original budget was set late December and then announced in early January. And our -- we're looking at 2009, our thought process was that gas would probably average close to $7 of Mcf and I think January it was $6 and then February we saw such a big drop off in gas. We went below $5 and I think getting below $5 was a signal that $7 was way off the mark and we really wanted to go into our secondary -- we call it the scorched earth budget and that's what we put out there, was that the easy reductions that had dropped off activity that we mainly had planned for the second half of the year, when we were ramping up with seven rigs in the Haynesville.

We still really don't have to make that decision until later in the year, as far as actually letting rigs go for when we get new rigs in. But -- it would be very easy for us to but the budget back to the higher number and if gas prices improve, but given the outlook that gas has now and the very low February prices we're going to realize, we thought it was best to make that the target budget, the lower budget.

Then we took the different areas, Dan. We said in south Texas all of that has held up production in Fandango the re-completions from 16,000 to 18,000 feet, we think we have a bunch of those to add reserves. That's all behind (inaudible) We own 100% of that, any rig completions from 12,000 to 16,000 feet in some of the 20 Fandango wells we pushed that off, because, again, we don't lose it. We did drill the well to the north and the south, the Musa and the Trevino. We are going to produce those until the end of the second quarter, and see what kind of decline curves we have, what type of bottom well pressure and if we need to drill more if commodity prices go up. We can do that. We don't lose acreage by not drilling those wells.

Same thing with the horizontal Cotton Valley Taylor, the 5, that acreage is held by production, so we don't lose the acreage. The same with the 18 vertical Cotton Valley wells. We have said, well, we can push most of those off because we don't do acreage there. We did it in $50 million increments, we just hunkered down and said what is it that we are really trying to do in '09 and do we have the services to drill the Haynesville wells and do we have the manpower? Do we have the expertise and then we put up this little chart, which is slide 17, that says, okay, we put up the score card. Here's the wells we are drilling and here's the ones we are completing, and we're just going to keep adding -- adding on to that.

But we want to -- we want to preserve our our credit facility. And I think that's -- you know, in the past, 10 years ago, we were young, stupid and naive and we thought we could get out of the credit crunches unscathed and I don't think any company can. And we don't want to get in that box. It's an ugly one. So as we said in January, we've got five rigs right now that have top drives and we are using to drill horizontal Haynesville wells in the third quarter. We'll get two more rigs and they are Helmerich and Payne rigs. We can elect then to either release two of our existing five top drive rigs and just keep a five well program or we can have a seven well program in the latter part of the third and the fourth quarter for Haynesville, as Roland said, we don't really have to make that decision now.

We did cut the budget back assuming that we will just have, like a five rig program, but if we wanted to ramp it back up again, I think we would -- we could do that. We just don't want to mislead you and how many wells you think we will drill now if we changed it.

Got it. Got it. And then you booked 13bs on the Linedecker. What is the final estimated drilling complete cost for that well?

It's probably going to be around $14 million.

Got it, okay. That's all I got. Thank you, gentlemen.

Thank you, Dan.

Our next question will come from the line of [Sven Dell Pozo]. With CK Cooper and Company. Please proceed.

Yes, it's [Sven Dell Pozo] with CK Cooper and Company. My questions relate to cost for the most part. I would like to know if you could decompose the operating expense of $1.37, for mcfe to break out the tax component to get a better feel for where your controllable lifting costs are trending.

Sure, the production taxes were only $1.8 million of the total $20.6 million in the fourth quarter. They have come down a bunch. Part of that was just in the lower prices. We had properties qualify for some reimbursements for type gas, of severance tax reimbursements.

Okay, is there any way to quantify that for the future. The properties which you have the severance tax reimbursements.

Well, many of the new properties end up qualified but you have to go through the process. So sometimes we -- we initially pay the taxes and then if they do qualify, they issue a refund and that's an ongoing kind of process. But generally the production taxes will kind of trend where -- where they are going to be tied to the -- really, the sales price for the most part, unlike most of the rest of the lifting cost is fixed.

Sure.

It tends to run 4% of our sales in total. So I think kind of -- if you kind of look forward and assume we have 3.5% to 4% would be severance tax and then the balance of the lifting cost is more of the fixed costs which really won't relate to prices too much.

Okay. And with the current price environment, am I looking at a fourth quarter, just lifting cost without the production taxes once I calculate that number? Is that still in the rear view mirror? In other words, are costs right now going even lower given the pull back in gas prices? Would I be -- is there some reason to think that lifting costs will be even lower? The future quarters?

Well, I think they will be lower than the fourth quarter. The fourth quarter we had about $1 million of additional lifting of the goods that were related to state ad valorem taxes, which are -- they are typically assessed late in the year. We accrue for them, but they -- when they came, in they were a lot higher than they were expecting them on some properties. So we had to catch up about $1 million. So I think if you look into the -- look into the future, I would expect our lifting costs outside of production taxes to be about $1 million less, just for that one kind of unusual adjustment.

Okay. So just to clarify, the total taxes -- the production taxes and the ad valorem taxes, if we call it all production taxes, would be about $2.8 million in the fourth quarter.

No. No. Much greater. The $1 million was just the part that we figured was really related to prior periods.

Oh. All right.

So the ad valorem taxes were probably about double that, probably in the fourth quarter.

And --

Usually that number isn't exactly -- it doesn't proportionally track sales prices because they set that once a year and they won't necessarily float with the sales price. So we consider that more of a fixed cost.

So just to clarify, the total production taxes in the fourth quarter, which we all call them production taxes plus severance, and ad valorem, all the taxes together, would be bigger than the 1.8 --

$1.8 million is only the severance taxes, period, yes.

Okay. And in the pretax, pv10, what are the future development costs used in that calculation and would you consider them to be a little bit aggressive in consideration of the fact that future development costs are probably on the decline?

Right. That's the one cost. That's the one -- the real -- something that's real out of balance in the year-end calculations because you have to use your average development costs and typically they want to see those tied into your 12-month average cost and then in 2008, we had a big run up in service costs and then you are using the December 31 prices. So you really had very high kind of costs per well that had to be used in the reserve report, which is just exaggerated. You know, the price revisions, because we do feel like some of those costs should come down. But basically we, in our total crude reserves, I think the total future development cost was $495 million.

Okay. All right. So it's going to be less than that?

It should be a little less than that.

Okay. And then finally, the G&A, am I correct that the cash portion of the G & A jumped up in the fourth quarter, versus the prior quarter, the third quarter?

Right. It was the G&A; typically the fourth quarter is higher than the other quarters, that's when performance bonuses and other type incentive payments were made. Those were higher than they were last year because the higher number of -- we have a -- probably a higher staffing level now and then also the Company had a great year last year. But that is probably --- you wouldn't assume that to be what it looked like in the first quarter. That first quarter, I think G&A will be back. It will probably be more like $8.5 million, but no more than $9 million. That will come down, along with lifting costs in the first quarter.

Okay. And back to Fandango, the two delineation wells that were being drilled, do you have any way of knowing -- is it too early to say that the two deliniation wells plus the discovery well will be able to drain the entirety of the field or it's too early to say at this point?

They are testing different fault blocks, so the south Texas geology is such that one well doesn't -- doesn't drain the whole field by any means. But, no, it's -- and it certainly is too early to give numbers. We like what we've seen. We want to get some tests -- test information on both of those wells before we issue any reserve estimate. Okay. And, pardon me, one last question for the DD & A rate going forward, I understand the unit escalation in the unit DD & A rate was primarily caused by negative revisions. I'm wondering if there's a general escalation in the DD & A rate owing to an increase in just plain capital costs experienced during 2008, such as steel and other input costs into the well. Is -- how -- could you guide me a little bit on that?

That was -- that would be true because basically D D & A rate is just a reflection of the finding cost when the properties are produced, so you had a combination of both, you have fairly high capital cost in 2008, which were capitalized on the successful wells and then I think when you are taking away reserves for price revisions, you have both of those effects working to raise the rate. What should lower the rate in the future is lower capital cost to the extent that we can benefit from that, but also when we really lower the rate is when we can add the Haynesville reserves and then see in the -- since those reserves were mainly in a lot of producing fields we have now, just a different formation, that should have the effect of really helping the rate but that will take several -- that could take two to three quarters before you really see the benefit of it.

Okay. All right. Well, thank you very much.

Thank you.

And our next question will come from the line of Rehan Rashid with FBR Capital Markets. Please proceed. [ Silence ]

Can you hear me? Can you hear me okay?

Yes, we hear you.

Hi, Rehan.

I'm sorry. So a question for Mack, actually, you said one of the goals for the year is 80 acre spacing, can you figure that one out. What would you like to see in terms of well performance to get comfortable with that 80 acre spacing thought process?

Well, given the wide footprint of our drilling program, we're not going to be drilling offsets -- immediate offsets to initial wells. We are drilling to prove up acreage and reserves, et cetera. So this year, I don't believe that many of the wells that we will drill will go directly to testing the 80-acre spacing. You know, what you want to see, obviously is lack of interference between wells -- you drill one well and 80 acres away you drill another well some time later. You would not want to see any kind of pressure draw down or interference. If you did, obviously, you are too close. So -- and there's various tests that can be conducted by our reservoir group here. That can also give us some hints -- some pretty good hints on the viability of the 80-acre spacing. All of the data that we have today, as well as the other operators, Rehan, suggest that currently, 80-acre spacing is valid.

I'm looking at page 17 and looking at the number 1, and the number 10 wells, bfmc12, I think they are very close to each other. Is that close enough, that -- that that would give you a feel for things or how far apart are they?

No, they are too far apart.

Okay. That's all I had. Thank you.

You're welcome.

And at this time, we have run out of time for any more questions. I would now like to turn the call back over to management for closing remarks.

Again, I don't want anyone to overlook the fact that we -- I mean, we had a phenomenal '08 year. I think there's a fine line between being very successful and having failure. And I think in '08, we were fortunate, again to have sold all of our offshore operations and sold $138 million of our non-core properties and no one knew that we would have a couple of hurricanes and we would have material decreases in oil and gas prices, certainly no one knew the credit crisis would be as bad as it is. And we had positioned ourselves for about a 17% debt to cap.

We still have 5.3 million shares of Stone which we plan on holding on to for a long time. Those shares are worth $9 or $10. We have written those down so there's no carry forward with any issues on that in the future and we literally are focused on creating wealth by adding reserves mainly, in East Texas, north Louisiana with a little bit of complimentary reserves in the Wilcox, the vertical wells and the directional wells in south Texas. As Jack and some others mentioned we -- maybe we will put a press release out in another six weeks or so. If we have enough information, that's important for it to go out, and if anything changes, we will notify you. I think it should be -- we have never been better positioned as a Company, ever, to grow than we are today. So I thank you for the hour and 40 minutes that you have been on the phone call. Thanks.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Good day.