Comstock Resources Inc (CRK) 2004 Q4 法說會逐字稿

Good morning, ladies and gentlemen. And welcome to the Year End Financial Results Conference Call. [Operator Instructions] I would now like to turn call over to Mr. Jay Allison. Mr. Allison, you may begin.

Yes mam, thank you. Welcome to Comstock Resources Fourth Quarter 2004 Financial and Operating Results Conference Call. You can view our slide presentation during or after this call by going to our website at www.comstockresources.com and clicking "presentations." There you will find a presentation entitled "fourth quarter 2004 results" to change the page in the presentation click the arrow -- the pa -- the arrow on the page. I am Jay Allison, President of Comstock and with me is Roland Burns, our Chief Financial Officer and Mack Good our Chief Operating Officer who will be available to answer questions. With this call I will review our financial and operating results for the fourth quarter and year ended 2004 as well as the results to date of our drilling program. Our discussions today will include forward looking statements within the meaning of securities laws. While we believe the expectations and such statements to be reasonable there can be no assurance that such expectations will prove to be, correct.

Page two. The 2004 Highlights. In 2004 we set new corporate records for revenues, EBITDAX and cash flow and we drilled more wells in a single year than in any other year in our corporate history. While we set corporate records for revenues, EBITDAX, and cash flow, our solid financial results were impacted by several factors. First we had the charge for the early retirement of the expensive 11.25 percent senior notes of $19.6 million which reduced our earnings per share by $0.35. We also adopted FAS123 early and began expensing stock options issued to our employees. We had $6.2 million in stock based compensation expense in 2004. Hurricane Ivan dealt a severe blow to Bois d'Arc Energy operations in the second half of the year, causing a deferral of 2.2 Bcfe production an increased cost for storm repairs and idle rigs waiting on clear weather. The hurricane also contributed to the delay of a start of our new production facility at Ver -- Vermillion 51 which was expected to boost our production beginning in November. We also had a 1-time charge for costs associated with the formation of Bois d'Arc Energy of $1.1 million and minor impairment of properties of $1.6 million in 2004.

We drilled more wells in 2004 than any other year in Comstock's history. We drilled 70 wells of which 58 were successful, giving us a success rate of 83 percent. In addition to our active drilling program, we executed a number of other initiatives. We strengthened our balance sheet. We further developed our relationship with our Gulf of Mexico exploration venture partner Bois d'Arc and we successfully acquired the assets of Ovation Energy. In February of 2004 we called our expensive 11.25 percent bonds and issued 6 7/8 percent bonds and on a pro forma basis saved our shareholders $11 million a year in interest expense. In July of 2004 we formed a new entity in partnership with our long-term venture partner Bois d'Arc which focuses exclusively on the shallow Gulf of Mexico. The refinancing of our loan to this entity will significantly improve our balance sheet.

Page three. Oil and Gas Sales. In the fourth of 2004 our oil and gas sales increased to $71.2 million, a 36 percent increase from sales of $52.5 million for 2003's fourth quarter. In 2 -- in 2004 our sales totaled $261.6 million, 11 percent higher than our sales in 2003 of $235.1 million.

Page 4. EBITDAX. Earnings before interest, taxes, depreciation, amortization and expiration expense and other non-cash expenses increased 42 percent in the fourth quarter of 2004 to $54.9 million as compared to $38.6 million in the fourth quarter of 2003. EBITDAX for the year ended 2004 was $202.6 million, an increase of 32 percent as compared to EBITDAX of $183 million for the year ended 2003.

Page 5. Cash Flow. Our cash flow from operations increased 56 percent in the fourth quarter of this year to $47.5 million from $30.4 million in the fourth quarter of 2003. Operating cash flow for 2004 was $176.2 million, a 16 percent increase as compared to cash flow of $152 million for 2003.

Page six. Earnings. For the fourth quarter of 2004 we reported a profit of $15.9 million, as compared to 2003's fourth quarter net income of $5.7 million. In 2004 we had net income of $46.9 million as compared to net income of $53.3 million for the year ended 2003. The results for the year ended 2004 include a charge of $19.6 million or 12.5 million after tax or $0.35 per share relating to the early retirement of our 11.25 percent senior notes and a $1.1 million charge or $0.03 per share related to the formation of Bois d'Arc Energy. Without the loss on the early extinguishment on the bonds and the Bois d'Arc formation cost charge we would have made $60.5 million for the year or $1.67 per share. Our 2004 results -- results also includes a charge for stock based compensation of $6.2 million or $0.11 per share including the expensing of employee stock options.

Page seven. Average Daily Production. Production in the fourth quarter of 2004 averaged 113 million cubic feet equivalent per day which is the same as our production rate in 2004's third quarter and seven percent lower than 2003's fourth quarter production rate of 121 million cubic feet equivalent per day. Bois d'Arc Energy's production averaged 31 million cubic feet equivalent per day. Our East Texas, North Louisiana region averaged 29 million cubic feet equivalent per day. Our Southeast Texas region averaged 27 million cubic feet equivalent per day. And our South Texas and other regions averaged 26 million cubic feet equivalent per day during the fourth quarter. Production was up in the other regions by eight million cubic feet equivalent per day because of the Ovation acquisition. The production losses at Bois d'Arc Energy which are caused by Hurricane Ivan offset this increase.

Average Oil Price. Page 8. Our average oil price increased 55 percent in the fourth quarter of 2004 to $47.06 per barrel as compared to $30.46 per barrel in the fourth quarter of 2003. For the year ended 2004 our average realized oil price increased 30 percent to $39.86 per barrel as compared to $30.70 per barrel in 2003.

Page 9. Average Gas Price. Our average gas price increased 43 percent in the fourth quarter of 2004 to $6.66 per Mcf as compared to $4.65 per Mcf in the fourth quarter of 2003. For the 12 months ended 2004, our average realized gas price of $5.98 was 11 percent higher than last year's average price of $5.41.

Page 10. Cost per Mcfe for the Fourth Quarter. Our lifting costs per Mcfe produced increased $0.31 in the fourth quarter of 2004 to $1.40 as compared to $1.09 in the fourth quarter of 2003. The increase is primarily attributable to the lost production during September to the Hurricane Ivan and repairs caused by the hurricane that was included in our lifting cost. Our G&A per Mcfe excluding stock based compensation increased $0.10 in the fourth quarter of 2004 to $0.27 as compared to $0.17 per Mcfe in 2003's fourth quarter. The increase was attributable to higher G&A associated with higher personnel costs and higher compliance costs relating to Sarbanes-Oxley. Our depreciation, depletion, and amortization for Mcfe produced increased $0.13 in the fourth of 2004 to $1.58 per Mcfe as compared to $1.45 per Mcfe in 2003's fourth quarter.

Page 11. Cost per Mcfe for Year Ended December 31 of 2004. Our lifting cost per Mcfe produced increased $0.18 for the year ended 2004 to $1.22 as compared to $1.04 for the year ended 2003. Our G&A per Mcfe excluding stock based compensation increased $0.10 for the year ended 2004 to $0.27 as compared to $0.17 per Mcf for the 12 months ended 2003. Our depreciation, depletion, and amortization per Mcfe produced increased $0.09 to $1.46 in 2004 as compared to $1.37 per Mcfe for the year ended 2003.

Page 12. Cash Margin Per Mcfe. Our cash margin on a per unit basis improved by 49 percent in the fourth quarter of 2004 to $5.19 as compared to 2003's fourth quarter cash margin of $3.49. For the year ended 2004 our cash margin was $4.71, a 13 percent increase as compared to a cash margin of $4.15 for the year ended 2003. The increase in our cash margin is attributable to the higher oil and natural gas prices.

Page 13. Capitalization. At the end of 2004 our debt increased to $403 million, up $57 million from our total debt of $324 million at the end of the second quarter. Our stock owners equity was $356 million, at the end of 2004, giving us a 53 percent debt to total capitalization ratio. $59.4 million of our debt is attributable to the other interest owners of Bois d'Arc Energy. Without the debt owed by the other Bois d'Arc contributors this ratio would be at 59 percent. After the closing of the planned refinancing of the Bois d'Arc Energy debt our debt to equity will fall to 46 percent on a pro forma basis.

Page 14. Capital Expenditures. We spent $209.4 million on our drilling and acquisition programs in 2004 as compared to $90.9 million in 2003. We spent $62.7 million in the acquisition of Oc -- on Ovation Energy. In 2004 we drilled 70 wells. 30.8 net wells to our interest. 58 of the 70 wells drilled in 2004 were successful and 12 were dry holes. We spent $68.6 million to drill 46 development wells of which 45 wells were successful. We spent an additional $26.1 million for work-overs and recompletions, offshore production facilities, and other development costs. We spent $52 million on our exploration program. $47 million was spent to drill 24 exploratory wells of which 13 were successful. Five million dollars was spent to acquire exploratory acreage.

Page 15. Proved Reserves. At the end of the year our proved reserves were 629 Bcfe with a PV10 value of $1.5 billion. Our reserves include 183 Bcfe relating to our 59.9 percent interest in Bois d'Arc Energy. The reserves are 67 percent proved developed and 79 percent natural gas. 80 percent of the reserves are operated by us or by Bois d'Arc. We added 55 Bcfe to our proved reserve base in 2004 and we replaced 128 percent of our production.

Page 16. East Texas, North Louisiana Region. At end of 2004 we had 201 Bcfe of our reserves or 32 percent in our East Texas, North Louisiana region. Our production averaged 28.1 million cubic feet equivalent per day in 2004 in this region which was 24 percent of our total production. Production was down eight percent from 2003. In the third quarter of last year we started drilling in this region and we spent $22 million to drill 16 development wells or 10.7 net wells to our interest. All of the wells were successful and had an initial daily production rate which averaged almost two million cubic feet equivalent per day, per well. These new wells came online late in 2004 or early this year which is too late to offset the production decline in this region.

Page 17. A graphic chart of our East Texas Drilling Program this year. This year East Texas will be the focus of our Development Drilling Program. In this low risk region we plan to drill 69 wells or 43.2 net wells to us. We have budgeted $62 million for this program. The majority of these wells will be drilled in the Beckville and Blocker Fields as shown on page 17 with a substantial increase in investment in this region we expect production to increase by 15 percent to 25 percent this year.

Page 18. The Gulf of Mexico Region. We have 183 Bcfe of our reserves or 29 percent in the state and federal waters in the Gulf of Mexico through our interest in Bois d'Arc Energy. The Gulf accounts for 32 percent of our daily production at 37.7 million cubic feet equivalent per day. Which is down seven percent from 2003's production from this region of 40.7million cubic feet equivalent per day. The decrease is a direct result of the impact that Hurricane Ivan had on Bois d'Arc's production during the last half of 2004. The hurricane caused production deferrals of approximately 2.2 Bcfe or 1.3 Bcfe to Comstock's interest. And it delayed the startup of a new production facility at Vermillion 51 from early November to late January which is now online and producing 30 million cubic feet equivalent per day.

Page 19. Our New Offshore Venture with Bois d'Arc. On July the 16th we contributed substantially all of our Gulf of Mexico properties in the 103 million in debt to Bois d'Arc Energy LLC, a newly formed company. Bois d'Arc resources and its two principals, Wayne Laufer and Gary Blackie together with certain of their partners also contributed their interest in their Gulf of Mexico properties to the new company. We received a 59.9 percent equity interest Bois d'Arc Energy for our contribution. The ownership interest was bases on reserves contributed. We have filed a registration statement for an initial public offering of the combined offshore venture. The registration statement is not currently effective. The proceeds of the offering will be used to repay the $148 million that Bois d'Arc currently owes Comstock.

Page 20. The Gulf of Mexico Region. We spent a total of $90 million last year in our Gulf of Mexico region. 19 out of 24 wells drilled were successful, giving us a success rate of 79 percent in the Gulf. A large part of our expenditures were for drilling developmental wells at the Ship Shoal 113 unit. In addition we spent 8.3 million for production facilities for discoveries that we made in 2003. We also drilled five expensive dry holes in 2004. As a result, we did not add many reserves to this region as compared to the dollars spent, but we did convert a substantial amount of reserves into proved producing.

In the fourth quarter Bois d'Arc drilled four successful wells and had one dry hole at Ship Shoal 69. The four successful wells included a well in south Timbalier Block 29 which is drilled to a total depth of 16,547 feet and logged approximately 76 net feet of pay in five sands. The second successful well, was drilled in Ship Shoal 113 unit to a total depth of 8,537 feet. This well logged approximately 173 feet of net pay in eight different sands. We drilled our third well in Ship Shoal 134 to a total depth of 7,000 feet which logged approximately 22 net feet of pay in three different sands. This well will be connected to an existing platform along with two other previously drilled wells in Ship Shoal Block 134 and 135 in the second quarter of this year. The fourth well, was drilled in Ship Shoal Block 99 and was drilled to a total depth of 12,400 feet and logged approximately eight net feet of pay in one sand.

2005 looks to be a very promising year in the Gulf as we have already drilled four more successful wells and we have had no dry holes in 2005. Of the four successful wells we have drilled this year, two are successful developmental wells at Ship Shoal Block 92 and 98. The remaining two were discovery wells including a well at Ship Shoal 111, drilled to test the Laker Prospect. And a successful well at South Pelto Block 14. We believe the two exploratory wells may have come close to replacing the reserves that we expect to produce in the gulf in 2005.

Page 21. Offshore Prospect Inventory. We think Bois d'Arc's most valuable asset is its prospect inventory and it's experienced technical staff. Bois d'Arc has an extensive inventory of offshore prospects which have been identified with 3D seismic on leases covering 132,000 acres in the Gulf. These 44 prospects have a potential of 877 Bcfe and will take two to three years to drill. At 2005 Bois d'Arc will spend over ten million dollars on acquiring new seismic data including new long cable data to assist it in evaluating deeper targets.

Page 22. Our Southeast Texas Region. In our Southeast Texas Region we have 113 Bcfe of our reserves which is 18 percent of our total reserves. This region accounts for 26 percent of our daily production at 30.5 million cubic feet equivalent per day which is down seven percent over 2003's production from this region of 32.8 million cubic feet equivalent per day. Production is down because we only drilled two wells in the region in 2004 and one of the wells has not yet been connected to sales.

Page 23. Poke County, Texas. Last year we drilled two wells to continue to delineate our Hammond Discovery which was made in 2002. The Davis Blackstone number one well, was drilled in early 2004 and had an initial production rate of 8.2 million cubic feet equivalent per day. The Collins number three was drilled in late 2004 and has yet to be tested due to delays in resolving pop-on rights of way. These have now been resolved and the well is expected to be on production by the end of the first quarter.

We spudded the Blackstone Mineral unit B number one well in late November to test our Big Sandy prospect to the south of the Double A Wells Field. The well has been directionally drilled to approximately 15,000 feet measured depth before encounting -- encountering mechanical difficulties that resulted in stuck drill pipe. Efforts to free the drill pipe were not successful and we are currently side tracking the well around the stuck drill pipe. We plan to drill and log the prospective upper Woodbine reservoir target and anticipate reaching that target again in late March of '05. We continue to remain very enthusiastic about the prospect's potential as the drilling problem was caused by sub surface blowout at around 15,000 feet measured depth. We retained a 100 percent working interest in this well. We plan to spend $18 million in this area this year on the Big Sandy and the drilling of three developmental wells in the field. We also hope to drill a deep exploratory well to test our Robin prospect located south of Big Sandy. Both the Big Sandy and the Robin each have over 150 Bcfe of reserve potential.

Page 24. South Texas Region. We have 51 Bcfe of our reserves or eight percent in our South Texas Region and about 11 percent of our production or 9.9 million cubic feet equivalent per day. Production from this region is 12.7 (inaudible) day equivalent per day is up 28 percent from 2003's production which averaged 9.9 million cubic feet equivalent per day. In 2004 we spent $21 million for drilling in our South Texas region to drill 26 wells, or 7.7 net wells to our interest. 19 of the 26 wells were successful and were tested at an average per well rate of 4.6 million cubic feet equivalent per day, per well.

In 2005 we will continue to develop the J.C. Martin Field where we drilled ten successful wells last year and the Ball Ranch where we had four successful wells last year. The highlight of the drilling program in this region last year was in the Javelina Field. The [Dub] number one well in the Javelina field was a discovery well, we drilled on a 1,282 acre farm-out from Shell. We tested this well at 10.1 million cubic feet equivalent per day. Comstock has drilled another well in the Javelina field this year. The dub number two logged approximately 86 net feet of pay in the Vicksburg Sand and is expected to have a similar initial production rate. We own a 50 percent interest in this play. This year we plan to spend 16 million in South Texas to drill 16 wells.

Page 25. Our Other Regions. We have 81 Bcfe of reserves in other regions including 29 Bcfe in the Mid Continent Region. 17 Bcfe in the San Juan Basin and 31 Bcfe in Kentucky. These properties account for seven percent of our daily production at eight million cubic feet equivalent per day which is up 18 percent over 2003's production of 6.6 million cubic feet equivalent per day.

Page 26. Our 2005 Outlook. Our drilling budget will approximate $175 million this year. With $75 million related to Bois d'Arc Energy and the balance to be spent on our onshore properties. The increased investment we are making in East Texas should provide a predictable increase to our onshore production levels this year. In addition we are finally over the effects of Hurricane Ivan in a new platform of Vermillion 51 and South Marsh Island was put online in late January of this year. As a result Bois d'Arc Energy's production level is currently around 74 million cubic feet equivalent per day or 44 million cubic feet equivalent per day net our interest. We are expecting our production to average between 120 to 130 million cubic feet equivalent per day in the first quarter and to increase 15 percent this year over 2004. And lastly, when Bois d'Arc completes its refinancing of our loan, which we now believe will not occur until early in the second quarter this year, our debt will fall to 46 percent of our total capitalization. With that, Sandra, I'll turn it over for questions.

[Operator Instructions] Wayne Andrews, Raymond James.

Hello, Jay, Roland and -- and Mack. Just a quick -- couple of quick questions. Jay, you said something I thought was interesting that you thought you might have actually replaced some where near to what you will produce in the Gulf with the first two exploratory wells and maybe you can give us a little more color on what kind of reserves and maybe not reserves but maybe even timing on when you expect those to come on? And you said South Pelto 14, I -- I assume that that is a deeper test and then your Ship Shoal 111? I have a follow-up question as well.

Yes I think, Wayne on that -- Let me comment on that and then Roland can -- can add on. With the relationship that we had with Gary and Wayne, of course, they were in charge of the drilling program offshore through the venture. And we, we -- I think we did have, was a series of bad wells in the third quarter and then actually one well in the fourth quarter of last year and we kind of come off of those two bad quarters and we have drilled two developmental wells this year and then, as I said, we drilled two exploratory wells and had two discoveries. If you look at the reserves that right now we would give toward those discoveries the comment that we make is that we feel like we'll produce anywhere from 30-33 Bcfe reserves in the Gulf this year with Bois d'Arc. And that the two wells that we have just drilled which are exploration wells we think that they have a chance to replace that production. I won't make any other comments and this is what management feels like we, potentially have hit.

You say that -- are those what you would call deep shelf targets in both of those wells?

Yes, that .

They weren't -- yes they weren't really that -- they weren't below 15,000 feet, Wayne. They were -- so they were kind of more intermediate kind of depth wells. So they weren't super expensive wells but they were just -- they looked very promising. It's pretty early though as they have just been drilled but they are wells that, don't require a -- a lot of infrastructure so they -- we could see some production this year.

Right. Very encouraging. And then I just -- following up a little bit on your Ark-La-Tex region where you are going to place a lot more emphasis this year. I know that in the past you have used a pretty low kind of commodity price to determ -- to rank your prospect inventory and maybe you could talk a little bit more on sort of what your decision was to place more emphasis in that area because I think it is an interesting concept and what needs to be done in the industry and I applaud your efforts to drill those low risk wells in this environment.

As you know, I mean you have known us for at least ten years, Wayne. In 1995 we made a big investment in East Texas, North Louisiana, with an acquisition and with that we -- we did accumulate quite an acreage position. And what we did when commodity prices went up, really in August of last year we kind of assessed how many drilling prospects we would have at a specific commodity price in that region and then we announced probably August or maybe September of last year that we anticipated drilling at least 50 wells in that region and in both 2005 and in 2006. So what we have done really on page 17, which is the first time if you go through the -- the webpage, you can see that out of the 21 major fields that -- that we own interest in we have delineated two of of those on page 17 to show you where the majority of these wells will be drilled both in Beckville and in Blocker and we show you specifically where they will be located so we can be accountable for that. Mack, do you want to make any comments on -- on program and how you assess those.

Sure, very quickly. We had tier ranked our East Texas assets as far as PUD locations. We had gone though this process, each year we go through this process of tier ranking our prospects and -- and what commodity price it would take to -- to make those wells fit our economic criteria. And early last year we had a ranking tier that presented us with over 100 PUD locations based on the current commodity pricing. So as you know, we very quickly hedged via costless collars a substantial portion of the East Texas production that we anticipate from the program. We developed service company alliances so that we could go forward with the ramp up on our drilling program. And the rest is just a matter of finding the number of drilling rigs to execute the program. Currently we have three rigs running in East Texas. We are -- we are improving our drill time curve so that we feel very confident we can get to that -- that goal of drilling 50 wells in our East Texas area.

Great, thanks. Look forward to a good year.

Historically, Wayne, what we focused on as you know is the Gulf of Mexico. And most of our -- our dollars either went to pay down debt or went to fund the Bois d'Arc program really. And so that's -- that's one of the reasons that in July of last year, you know, we said here is a new entity, it is Bois d'Arc. We own 59.9 percent of it. We would like to do an IPO. We filed the registration statement in October and again I think kind of early mid part of the second quarter this year hopefully that will be completed and our debt to cap will be reduced and -- and it will be a nice company that has a nice acreage position. And that what allows us to do onshore, which goes back to your east Texas question, it -- it allows us to develop these properties that Mack has been wanting to develop the last couple of years.

Yes, that's -- that is exactly what I was after, Jay is the fact that you have historically used sort of a two to 3-dollar gas price to rank your prospects and the East Texas and North Louisiana properties haven't necessarily met your hurdle rate. But because the Gulf of Mexico just stands out so well but if you -- if you actually look at those properties now maybe with the, four or even five dollar gas price and have a 90 to 100 percent success rate you are generating great returns on those.

Right and I think that goes back to, the whole industry. If you look at a three dollar or $3.50 gas price we would not drill the East Texas prospects because they are not that profitable. But take a price tag that is, five, five fifty, six or higher, which is were it is today and you look at our cost of entering that area, which is about ten years ago we just fortunately, had a lot of value there and we got prospects that -- that we need to drill.

Very good. Thanks for your time.

Thank you, Wayne.

Larry Busnardo, Petrie Parkman

Good morning. Have you given a reserve size for the prospect where the Collins Well, is drilling and then also on that -- that Hammond Discovery?

Have you -- Larry, are you talking about the Big Sandy prospect?

No, above that. Actually were the Collins -- do -- do you have a reserve size for the Collin well -- Collins Well? Or --?

Well number three is a development well, but it's probably a --.

Probably three Bcfe and we're -- we're in the process of evaluating that.

Okay. Was there a predrill on that prospect at all?

It was really not a prospect.

It was a development well.

So probably a similar number. It is kind of at the trying to determine the edge of the Hammond structure so, this is -- .

We are delineating the Ross area and so we are -- we are pushing the boundaries of that feature.

Okay. And then that Davis Blackstone Well, was that same type, kind of three to five Bs? Somewhere in there maybe?

Correct.

Okay. How many wells do you plan on -- additional wells in '05 do you plan on drilling in that area in 2005?

In the Ross area?

Yes.

We have one scheduled in Ross right now. We are extending, as you know, with Big Sandy to the south. And once we get the results on Big Sandy One that will tell us a lot about what we want -- want to do as far as drilling subsequent wells and where. But we have the one pro -- development well in the Ross area that -- that we have budgeted.

And we have, Larry, two additional development wells on the -- on the Double A Wells Field itself budgeted, also for this year.

Right.

And then, of course, the -- the cost of the test of the Big Sandy plus, we hope to start the -- toward the in the fourth quarter to try to test the Robin Prospect so we have got some dollars budgeted for that also.

What is the likelihood that -- that those get spud in the fourth quarter? Did you feel pretty good about that?

It really depends on getting a -- a permit approved for surface location inside of the thicket and we started that process but it is not far enough along to really be able to predict that. But we are -- we are aggressively pursuing it. And we are hopeful we can get that permit and if we can we spud it.

And, Larry if you go back to Big Sandy, of course the rig location is out of the thicket and it's a directional well underneath the thicket and when we had the sub-surface blowout for two days, I mean the well was out of control so you had to kill the well. Well when that happened you have got drill pipe that's -- that's, just sitting there and it's sticking to the hole and for about a month we have fought that problem. That's why we're side-tracking that well. If -- if in fact we had had a location in the thicket it be -- goes -- both the Big Sandy and particularly the Robin and you are drilling a vertical well, there is a great chance that -- that the problem we've had drilling the Big Sandy wouldn't exist. Because you wouldn't have directional drill pipe sitting on the -- the side of the mud walls. So that is why we do need -- we can drill that Ro -- the Robin outside the thicket but it -- it's a lot of riskier and a lot more expensive.

Okay. Great, thank you.

Ron Mills, Johnson Rice.

Guys, staying in that area with -- starting I guess with Big Sandy and then also with Robin, have you all maintained 100 percent interest in both of those wells?

Yes, we have.

Ronald Mills: And the, as I -- as I recall both of those of kind of 100 Bcfe type targets?

Yes. Both of them in fact are about 150 Bcfe targets and that, that, Ron, that includes initially if you look at Big Sandy we wanted to test not only the upper woodbine but we wanted to test the lower woodbine. And now what's happened, something is at 15,000 feet measured depth and that is not the upper woodbine. So you want to redrill through that problem area and find out what happened and we want to deepen the well to the upper woodbine. But on the first Big Sandy well, the chances are slim that we will get to the lower woodbine on that well. I mean, Mack still thinks there is a chance. But I'd say it's pretty minimal, which means we will drill another kind of Big Sandy well to test the lower woodbine. And the Robin prospect would -- would test the lower woodbine.

I would like to add something real quick about those prospects. As you -- as you know, we have a geological model that allowed us and allows us to be successful in the Ross area. And analyzing all of the offset wells on either side of the Big Thicket correlating to the seismic and within the context of our geological model, it will supported and supports the drilling of Big Sandy to the extent that we felt very comfortable keeping 100 percent of not only the Big Sandy prospect region but also extending southward to Robin.

Okay and then if you look at -- at just those two wells and with -- especially now with -- with the sidetrack, what do you think the -- the new CapEx on these wells will be in 2005?

Let's just talk about Big Sandy. We had budgeted and again as you -- as you asked we own 100 percent of that well. We had budgeted about five million dollars on that well. We will spend probably nine million dollars on that well. And if it is a dry hole in the first quarter we will take a nine million dollar charge. If it is a good well then everybody would be really happy. But it is a lot more expensive well than what we budgeted because we did lose about I'd say at least four, maybe five weeks because of drilling problems. And what happened, at this 15,000 foot measured depth we hit a sand that -- that has not been productive, I guess you would say, in that area. But it's -- it is quite obvious that there is something there. That does not mean, Ron, that that can be a good well. That can still be a dry hole. Until you drill through that sand and you drill the upper woodbine and log it you don't know what you have. But we do know there is something there and we do know that causes to lose that well.

Basically simply put, we hit an abnormally pressured, gas charged interval where none had been found in any offset well previously. And as a result we had a well control issue that resulted in stuck drill pipe that we have been dealing with since that time.

Okay. And then moving to follow-up on Wayne's question on East Texas as I recall you have 13 or 14,000 acres in that area. And I know you have talked in the past about having kind of three tiers worth of projects in terms of 100 great A's and -- and a couple hundred that --that -- based on -- on the knowledge today that, that you wouldn't -- you wouldn't have labeled grade A's. Are you doing more work in -- in moving -- moving more of those -- between 101 and 300 locations to -- closer to grade A.

Well I will comment and then I want Mack to. What we have done, most of the prospects that we mentioned, it's about 12,000 acres. And it's, 40 acre spacing, it's about 300 potential drill sites. What we said is we scrubbed it down. We're -- we're -- we're comfortable with 100 of those. In fact, over 50 or 60 of those will be drilled this year. Now, that -- that mainly is Cotton Valley. So you have other formations that are productive in that area and we have not allocated -- quote drill size to those -- to those prospects. You might want to comment on that.

Very quickly, Comstock's Land Department has done a great job in helping us -- it -- it's one thing to have grade A well locations to drill. It is quite another to make sure you can get the -- the drill-able location you want out in the real world. And we have been putting those grade A inventory wells on a -- on a drill inventory list. In other words, those locations are built and the drilling rigs can move directly to them. We have approximately 40 of those pretty much ready to go. In terms of tier ranking, lower -- the lower ranked wells previously, lower ranked wells and moving them up into a higher category. Yes, we have done some of that because as we -- we've drilled wells in certain areas we've -- we've shown that the -- the performance supports drilling additional wells that -- that were previously categorized at a lower rank. So yes, sir, we have done some of that.

And, I'm assuming in addition to kind of are you talking about potential Travis Peak or just -- or what were some of the other formations?

Most of the -- the targets we have are our Cotton Valley but we do have some kind of Houston and Travis Peak potential in Western Louisiana and -- and we are pursuing some of those opportunities is as well.

Okay. And then finally, just one quick question on Bois d'Arc (inaudible). I think you mentioned the production there you expect -- or is currently around 74 million a day. And --and for the -- for the full year the -- the average production would have been on what you stated would be 80 to 90 million a day. Can you walk us through kind of what some of the development timelines are to -- to ramp up that Bois d'Arc production?

Ron, they expect to be over -- I think it is as early as next month to be in the eight -- over 80 million a day. They have -- they are hooking up some additional wells, next month and -- and so that -- they -- we should be well over 80 and hopefully building on that as the year goes on.

Okay, thank you.

Ron, as you know, near the production in the Gulf dropped to about 50 million a day and that is a total result of Hurricane Ivan and the lack of being able to -- to have the crews connect Vermillion 51 to sales.

Kelly Krenger, Banc of America Securities.

Good morning. I have three questions. First on the production guidance that you gave for 2005 that was up 15 percent. Is that going to be on a reported year-over-year basis? I know you had two quarters of -- of 60 -- 59.9 percent of Bois d'Arc in 2004. And just curious as to what the right comp for that 15 percent production growth is?

Kelly, we are looking at that -- that as being measured over, 2004's reported volumes which we either had the Gulf of Mexico properties in the first half and then 59.9 percent of Bois d'Arc in the second half. And then we are looking at '05 still at a proportional consolidation basis. Because -- but again, when -- when -- when if when Bois d'Arc completes it's offering, then there will be a change in the control structure again that will require evaluation and potentially we -- it -- if we -- if we own over 50 percent or are deemed to control the company at that point, we will be consolidating. And so -- but we are not factoring in that -- that -- that as a part of that growth. We are looking at really -- if you look our -- proportionately the properties, if you just assumed we stayed at the same ownership of Bois d'Arc for the rest of the year, that is kind of how we are measuring it. Consolidation would add, more production, I guess to the reported numbers but then the benefit to that new production, of course would belong to the minority interest owners if we did report it. So it wouldn't have any real impact on us.

Okay. And then secondly, the -- the -- have you noted the -- the lease operating expenses per unit were higher in the fourth quarter due to the hurricane. Do you know how much higher they were as a result of that? And what kind of -- where do you see those in 2005?

Okay. That's a good question, Yes but basically in the fourth quarter, Bois d'Arc's lifting costs were up about two million dollars. Which that means about 1.1 or so that kind of flows into our numbers. And a large percentage of that was actual repairs that we did expense in lifting costs that -- that just -- the repairs were not quite large enough, to file insurance on because then you would lose your no claims bonus and other things. So it's kind of like, you do a little fender bender on your car and you are making the decision whether or not to turn it in to the insurance, which you could, but then it might cost you more in the long run. So we ended up decided not turn any of our claims in and -- and to go ahead and expense all of those so that is why we have those in the fourth quarter. These were just repairs to our production infrastructure like navigation aids and stuff that were damaged and what ever -- and fairly minor nature, but with all the infrastructure out there, there was a lot to get done. So thats in lifted that's probably not a recurring item. Although I think we are also looking at -- as we're looking at lifting cost, overall, -- costs are not going down. It seems like in the oil field there -- there going up. Just the basic cost of services such as -- especially if you have any work-overs or -- or all that type, all of the cost of services seem to be increasing. The base part of the lifting cost which relates to personnel -- our company personnel, probably remains fairly stable. And in May on a per unit basis actually improved because of the new production that Mack is going to put online. But again, with the commodity price environment we are in now, we would say that, probably our lifting cost should average maybe about $1.20 -- $1.20 per Mcfe on a go-forward basis right -- looking into '05 on a kind of a normalized basis.

Okay.

That we are not probably going to get them down, to the lower levels. Of course the higher commodity prices create higher advelorum (ph) and severance taxes that, that add 30 or plus cents or so to the aloway (ph) from a lower price environment.

So it sounds like a little bit higher in the first quarter and then turned down.

Right. I think the fourth quarter should have the unusual -- has some -- some unusual charges at Bois d'Arc. Comstock's onshore piece though, if you look at it is probably fairly normalized there. There's nothing unusual in it's fourth quarter rate. You see, the additional lifting cost that we incurred relates to the new properties that we, -- the Ovation Properties that came into the mix at the beginning of the fourth quarter.

Okay. And then last question. Your -- your -- your debt was 20 or $30 million lower at the end of the year than what I had modeled. Is there anything unusual in your debt balance at the end of the year? How -- how -- how much cash flow you had that you were able to pay down debt at the end of the year?

We were able to -- despite the -- the -- the lower production level, yes we -- we're able to -- with the hot commodity prices, really benefit us in the cash flow area. So we were able to, pay down some debt, there at year end. And so we was a little better and expected. But there is no real -- nothing really unusual, about that.

Okay. Okay. Thank you.

Thank you, Kelly.

[Operator Instructions] Gentlemen, at this time I'm showing we have no further questions.

Sandra, thank you. Thanks everyone.

Ladies and gentlemen this concludes today's teleconference. Thank you for participating. You may now disconnect.