Comstock Resources Inc (CRK) 2003 Q4 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the fourth quarter and year-end financial results conference call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. I would now like to turn the call over to Mr. Jay Allison. Mr. Alison, you may begin.

Thank you, Elsa. Welcome to Comstock Resources' fourth quarter 2003 financial and operating results conference call. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and clicking "Presentations." There you'll find a presentation entitled “Fourth Quarter 2003 Results.” To change the page in the presentation, click on the arrow on the page.

I am Jay Allison, President of Comstock, and with me this morning is Roland Burns, our Chief Financial Officer (technical difficulty)

With this call, I review our 2003 fourth-quarter and year-end financial results, as well as the results of our 2003 drilling program.

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

We are in the first day of a proposed offering of new senior notes that will be used to refinance our existing notes. For any of you on this call who are prospective investors in the new notes, you are welcome to listen in on the call. However, we have scheduled a separate call for the notes offering and related questions and answers for that this afternoon at 1:15 PM. Here are the details for today's 1:15 PM Eastern conference call for the notes offering. The conference call-in number is 800-374-2391, and the pass code is 560-2471. This will enable us to focus this call on questions related to the fourth quarter and year-end results.

With that, if you're following this on the webcast, if you'd go to page 2, which is 2003 highlights -- we were able to set new corporate high records in 2003 for revenues, net income, cash flow, and production. Our revenues soared to $235.1 million. We made a profit of $53.4 million and generated operating cash flow of $152 million. And our production reached 44 Bcfe. We were also able to greatly improve our balance sheet in 2003. We paid down $60 million of our long-term debt with our free cash flow and lowered our debt to total capitalization from 62 percent at the end of 2002 to 51 percent at the end of 2003. Our drilling program delivered production and reserve growth in 2003. Out of the 53 wells we drilled, we had 45 successes, giving us an 85 percent success rate.

The fourth quarter financial results, when we reported income of $5.7 million, is not as strong as compared to the earlier three quarters due to several factors. Gas prices were down from where they had been a year earlier, and our production was down about 2.5 percent from the third quarter instead of up because of delays in getting some of our Gulf of Mexico production online, and we took a $4.3 million impairment in the fourth quarter primarily on one of our outside-operated offshore properties, where we do not feel that we will recover our remaining book value from the future operations.

Page 3 -- oil and gas sales. Oil and gas sales increased production, and strong crude oil and natural gas prices accounted for the significant increases in our oil and gas sales in 2003. Our fourth-quarter sales of $52.5 million were up 25 percent as compared to 2002's fourth-quarter sales of $42 million. For all of 2003, our oil and gas sales totaled $253.1 million, a new corporate high and an increase of 65 percent over 2002 sales of $142.1 million.

Page 4 -- EBITDAX. Earnings before interest, taxes, depreciation, amortization, and exploration expense, or EBITDAX, was down slightly in the fourth quarter of 2003 to $38.5 million as compared to $38.7 million in the fourth quarter 2002. 2002's fourth quarter had the benefit of $7.7 million in other income relating to refunds received for prior-year severance taxes. Without this special item, EBITDAX would have increased by 24 percent in the fourth quarter of 2003. EBITDAX for the full year in 2003 grew 67 percent to $182.6 million as compared to $109.1 million in 2002.

Page 5 -- operating cash flow. Our cash flow from operations decreased 1 percent in the fourth quarter of this year to $30.4 million from $30.8 million in the fourth quarter of 2002. Again, this is due to the 7.7 million of other income in 2002 which bolstered up the 2002 amount. Without this special item, our cash flow would have been up by 32 percent. Operating cash flow for the full year of 2003 was $152 million, up 92 percent from cash flow of $79.3 million for 2002.

Page 6 -- earnings. We reported a net profit of $5.7 million for the fourth quarter of 2003 as compared to $9.5 million for the fourth quarter of 2002. We had 16 cents in earnings per share in the fourth quarter of 2003 as compared to 29 cents per share in 2002's fourth quarter. Even though our sales were up 25 percent in the fourth quarter of 2003, our net income decreased by 40 percent when compared to the fourth quarter of 2002. The 2003 results included a $4.3 million impairment, while the 2002 results included the $7.7 million in other income for the tax refunds. For the year 2003, we reported the highest net income of any year in our corporate history, with a profit of $53.4 million, or $52.7 million excluding a $700,000 gain resulting from adopting a new accounting principle. This compares to $11 million of profits from continuing operations in 2002. For 2003, our earnings per share were $1.53, or $1.51 excluding the gain relating to the accounting change, as compared to $0.37 per share in 2002.

Page 7 -- average daily production. Production for 2003 increased by 7.5 percent from $112 million cubic feet equivalent per day in 2002 to 121 million cubic feet equivalent per day. The Gulf of Mexico region accounted for much of the increase with its growth of 21 percent. Our Southeast Texas region grew by 11 percent, and South Texas was up by almost 41 percent. Our East Texas/North Louisiana region declined by 11 percent. Production in the fourth quarter averaged 120 million cubic feet equivalent per day, which represented a 9 percent increase from 2002's fourth-quarter production level of 110 million cubic feet equivalent per day. Our current production rate is at 120 million cubic feet equivalent per day.

Page 8 -- average oil price. Our average oil price realizations were up in 2003, both in the fourth quarter and for the year ended 2003. For the fourth quarter of 2003, our realized crude oil price increased 12 percent to $27.26 from $30.46 in the fourth quarter of 2002. For the year ended 2003, our average oil price increased 23 percent to $30.70 as compared to $24.95 for the same period in 2002.

Page 9 -- average gas price. Our gas price realizations increased significantly in 2003 over last year. Our average realized gas price in the fourth quarter was $4.65, 14 percent higher than our fourth quarter of 2002 average price of $4.07. For the year ended 2003, our gas price averaged $5.41, 64 percent higher than our average price of $3.30 for the year ended 2002.

Page 10 -- cost per Mcfe. Our listing cost per Mcfe increased to $1.09 in 2003's fourth quarter from 89 cents in 2002's fourth quarter. The increase is attributable mainly to higher production and ad valorem (ph) taxes related to increased oil and gas prices. In addition, we had higher insurance costs, especially from our offshore properties, as well as higher fixed operating costs from the ship shoal 113 (ph) units as we increased our ownership interest by acquiring Conoco Philips' (ph) interests. Our G&A expense per Mcfe decreased to 18 cents in the fourth quarter of 2003 from 21 cents for the fourth quarter (technical difficulty) 2002. Our depreciation, depletion, and amortization per Mcfe produced has increased by 7 cents to $1.45 for the fourth quarter of 2003 as compared to $1.35 for the same period in 2002.

Page 11 -- cost per unit of production. Listing cost per Mcfe produced increased by 22 cents or $1.04 for the year ended 2003 from 82 cents for the same period in 2002 -- again, mostly due to higher production and ad valorem taxes attributable to the higher oil and gas prices in 2003. Our G&A expense per Mcfe increased 4 cents for the full year of 2003 to 16 cents as compared to 12 cents for the year ended 2002. The increase related to higher personnel costs and our opening of a Houston office to oversee our offshore operations. Depreciation, depletion and amortization per Mcfe produced increased by 8 cents for the year ended 2003 to $1.37 as compared to $1.29 for the year ended 2002. The higher DD&A rate results from the increase in production from some of our higher cost properties, especially in the Gulf of Mexico.

Page 12 -- cash margin. Due mainly to higher oil and gas prices, our cash margin per unit of production increased 14 percent in the fourth quarter of 2003 to $3.48 per Mcfe as compared to $3.06 in 2002's fourth quarter. Our cash margin for the full year of 2003 increased 64 percent to $4.14 per Mcfe as compared to $2.52 per Mcfe for the same period last year.

Page 13 -- capitalization -- looking at our balance sheet. Twelve months ago, we stated that one of our goals was to improve our balance sheet. We believe that we made significant progress toward that end this year. Concerning debt reduction, at the end of 2003, we had $306 million in total debt. Of that amount, 86 million was debt outstanding under our bank facility, which had a $260 million borrowing base, giving us 174 million of availability. During 2003, we reduced our bank debt by $60 million, from $146 million at the end of 2002 to $86 million as of December 31, 2003. Concerning stockholders' equity -- the conversion of our preferred stock increased equity by $17 million and saved us $1.6 million a year in dividends. And our record-setting profits of $53 million accounted for most of the rest of the $64 million increase in book equity, which was at $290 million at the end of 2003. Debt as a percent of our total book capitalization has fallen from 62 percent at the end of 2002's fourth quarter to 51 percent at the end of this quarter.

As we announced last week, we are in the process of restructuring our long-term debt to take advantage of the current low interest rate environment. We have launched a tender offer for our 11-1/4 percent bonds and have arranged for a new $400 million bank credit (ph) facility with an initial borrowing base of $310 million. We also are in the process of launching a $150 million offering of new senior notes. If the offering is successful, we believe we can reduce our interest expense by almost 50 percent and more than double our maturities from an average of 2.4 years to 5.9 years. The tender offer will result in an after-tax loss on early extinguishment of debt of $13 million.

Page 14 -- capital expenditures. In 2003, we had $90.9 million in oil and gas capital expenditures. This represents an 11 percent increase over 2002's capital expenditures of $82 million. We spent 4.8 million on acquisitions, which mostly related to acquiring additional interest in the Ship Shoal 113 unit. We spent $28.3 million to build 35 development wells, of which 31 were successful, giving us a development drilling success rate of 89 percent. We spent an additional $18.6 million for workovers and recompletions, offshore production facilities, and other development costs. We spent $34.8 million on our exploration program to drill 18 exploratory wells. Of the 18 exploratory wells we drilled, 14 were successful, giving us an exploration drilling success rate of 78 percent. We spent $4.4 million on exploratory acreage.

Overall, we had $1.94 per Mcf (ph) and all-in finding (ph) costs in 2003. The finding cost was impacted by some negative revisions in the 2002 reserve estimates that related to performance from certain properties which totaled 19 Bcfe. Without the revisions, our finding costs would have come in at $1.37 per Mcfe.

Page 15 -- our four regions, the first being East Texas/North Louisiana. At the end of 2002, we had 175 Bcfes of our reserves, or 28 percent, in our East Texas/North Louisiana region. Our production averaged 30.6 million cubic feet equivalent per day in 2003 in this region, which was 25 percent of our total corporate production. Due to our limited reinvestment in this region, our production declined by 10 percent from 2002's average production rate of 34.2 million cubic feet equivalent per day. We spent $6 million and drill five wells in 2003. Four of these wells were successful development wells, and one was an unsuccessful exploratory test drilled in North Louisiana. The successful wells have been tested at a per-well (ph) rate of 1.7 million cubic feet equivalent per day. We will spend $7 million this year to drill six development wells in this region.

Page 16 -- our Southeast Texas region. In our Southeast Texas region we had 127 Bcfe of our reserves, which is 21 percent of our total reserves. This region accounts for 27 percent of our daily production at 32.8 million cubic feet equivalent per day, which is up 11 percent over 2002's production from this region of 29.5 million cubic feet equivalent per day.

Page 17 -- the Robin and Ross prospects. Last year, we drilled three wells to continue to delineate our Hamman discovery which was made in 2002. The Collins #2 well and the Hamman #3 well were successful, while the Hamman #2 drilled to the north was not. And the Hamman #3 was just put to sales (ph) last week, and is flowing at 8.5 million cubic feet equivalent per day. We have a 58 percent working interest in this well and the other Ross-area wells. We are in the process of obtaining 75 square miles of 3-D seismic over our Ross and Robin prospects, as well as Anadarko's discovery south of the Hamman. We plan to spend $20 million in this area this year to drill six wells, including a well to test our high impact Robin prospect. We hope to spread (ph) the Robin prospect well in the fourth quarter of this year. The timing is subject to our receipt and processing of the 3-D seismic data and obtaining permits from the park service to drill in the Big Thicket.

Page 18 -- our South Texas region. We have 47 Bcfe of our reserves, or 8 percent, in our South Texas region, and about 8 percent of our production, or 9.9 million cubic feet equivalent per day. Production from this region is up 41 percent from 2002's production, which averaged 7 million cubic feet equivalent per day. In 2003, we spent $15 million for drilling in our South Texas region and had good results. We drilled 13 wells. 9 of the 13 wells were successful, and were tested at an average per well rate of 7.4 million cubic feet equivalent per day. This year, we plan to spend 15 million in South Texas to drill 15 wells. We will continue to develop the Ball Ranch where we will drill five more wells, as well as test several other 3-D seismic-defined exploration prospects in this region.

Page 19 -- the Gulf of Mexico region. We have 216 Bcfe of our reserves, or 35 percent, in the state and federal waters of the Gulf of Mexico. The Gulf accounts for 34 percent of our daily production at 40.7 million cubic feet equivalent per day, which is up 21 percent over 2002's production from this region of 33.6 million cubic feet equivalent per day. We spent a total of $60 million last year in the Gulf and all of our wells were successful. Only five of these wells have been completed and were tested at an average per well rate of 5.6 million cubic feet equivalent per day. During the fourth quarter, we drilled two additional successful wells in our ongoing redevelopment program at Ship Shoal 113. The OCS-G 66 V4 well was drilled to a total depth of 11,824 feet, and logged approximate 111 net feet of pay in five sands (ph), and the OCS-G 6 #V5 well was drilled to a total depth of 10,621 feet, and logged approximately 143 net feet of pay in five sands (ph). We own a 72 percent working interest in these wells.

We also had three discoveries in the fourth quarter in our exploration program with Bois d'Arc Offshore Limited. The OCS-G 22 648 #1 well at South Marsh Island Block 220 was drilled to a total depth of 9,966 feet, and logged approximately 38 net feet of pay, and the OCS-G 22 605 #1 well at Vermilion Block 51 was drilled to a total depth of 10,169 feet, and logged approximately 74 net feet of pay in five sands. A successful development well was also drilled at Vermilion Block 51, which is the OCS-G 22605 #2 well. We have a 40 percent working interest in these wells.

In addition to the 18 wells drilled in the Gulf in 2003, we have drilled four additional successful wells in the Gulf of Mexico so far in 2004. One of these is in the Ship Shoal 113 unit, and three are with Bois d' Arc Offshore Limited, including a second successful well at Vermilion Block 122, a successful re-entry of a well at South Timbalier Block 11, and another delineation well at South Pelto Block 22. The OCS-G 18 054 #5 well was drilled to a total depth of 18,001 feet, and logged 291 net feet of pay in nine sands, including sands in a new fault block (ph) adjacent to the fault block that was tested by the number two discovery well in April of last year.

A four-pile production facility is currently under construction. It is anticipated to be installed by the end of the first quarter to allow production start-up from the three successful wells in the second quarter. We have a 29 percent working interest in the South Pelto Block 22 leasehold. This year, we have budgeted $67 million to drill 24 wells, including five deep shaft wells.

Page 20 -- expected connection timing. This is the connection times. This is a very important page on the webcast. At this time, we have 19 wells in the Gulf of Mexico that are awaiting completion or connection to production facilities. We believe that these wells will add almost 39 million cubic feet equivalent to our daily production level. Included in our presentation is a timeline on which we think these wells will be connected to sales. We expect to add around 10 million cubic feet equivalent per day in March and around 15 million cubic feet equivalent per day in April. If we meet this timeline, our second quarter production should be up significantly.

Finally, page 21 -- 2004 outlook -- outlook for the rest of the year. We have set our capital expenditure budget for development and exploration activities for 2004 at $110 million. This represents a 27 percent increase over the $86.8 million spent in 2003 for development and exploration activities. We plan to drill 61 wells, or 35.6 net wells. Of the wells planned, 28 wells are development wells and 33 are exploratory wells. Exploration-related projects will represent approximately 66 percent of the total amount budgeted in 2004. Our exploration program will be fed by our multiyear inventory of drilling prospects in the Gulf of Mexico and Southeast Texas. We expect our production to continue to increase in 2004 as we are able to hook up more of the offshore discoveries that we have made. We currently have 19 wells that have been drilled that are expected to be able to add almost 39 million cubic feet equivalent per day to our net production rate. These projects are expected to come online in various dates and should have significant impact starting in the second quarter.

We are in the process of refinancing all of our debt. If successful, we believe that we can almost cut our interest expense in half and more than double our average maturities. And lastly, with continued strong natural gas prices in 2004 and increased production, we should be able to continue to generate substantial cash flow in excess of our capital expenditures which will allow us to pay down more of our debt and continue to enhance our balance sheet.

And a final closing -- again, we are in the first day of a proposed offering of new senior notes that will be used to refinance our existing senior notes. For any of you on this call who are prospective investors in the new notes, we have scheduled a separate call for the note offering (technical difficulty) and related questions and answers for this afternoon at 1:15. That conference call-in number is 800-374-2391 with a pass code of 560-2471. With that, Elsa, let me turn it over for questions, please.

Thank you. We will now begin the question answer session. (OPERATOR INSTRUCTIONS). Ron Mills, Johnson Rice. Please go ahead.

Good morning, guys, how are you all today? Quick question -- just a clarification for the current production level. I missed that. Can you repeat that please?

We are at 125 million a day.

Jay, I think you actually said 120, but --

Oh, I'm sorry --

You kind of made my eyes go up (indiscernible) I think we're at 125 a day.

We are 125 million a day equivalent, Ron.

125. And then, with the timing of the production coming on, and given your, just, natural decline rate, are you expecting, Roland, the first quarter production to be pretty flat, or at least maybe slightly higher than the fourth quarter?

Yes, we are expecting that, Ron, to be just slightly higher. But you know in that range. And then really, the second quarter is when we see the increase coming from the Gulf of Mexico wells, as kind of outlined on that timeline.

Okay. And you talked about South Pelto 22, with the (indiscernible) wells in the startup, kind of, early in the second quarter. What is the timing at South Pelto 25? I know that the expectation was for that to be installed -- no, the facility is already there -- but, come online by the end of this month or early next. Is that still on track? I can't read that chart, is my problem.

Okay, I'm sorry. You need a magnifying glass.

Exactly.

We have -- what we have on that chart, and I don't know if we can blow up or not, I'll ask Roland if they can do that. But, after the South Pelto 22 wells the second set of wells is the South Pelto 25 wells, and you can see, production should start, really, March 1st.

Actually (indiscernible) come on first -- you know, the facilities are there for that project. It's just been really rough seas. So even though we have had a pipeline crew out there to hook it up, they had been on standby and just hanging out at the port, I guess, for a while. So it’s been rough weather in the Gulf. So that would have been already on by now. But it should be as soon as they get calm weather, they should have that flowing. Hopefully, I think Mack it in his schedule here, in early March.

Yes, we at first sales of March first really, and as Roland said, it is not an issue of the facilities, we are going to have, I think, calm seas for about four days.

The other thing we have done on that, Ron, and again, I don’t guess you can read it on the web site. On that page, we have put our net revenue interest for each of the wells in each of the areas. We have put what we think the initial production will be, and we have broken it out by regions and by wells, and then we have a net production figure, and we have a gross production figure.

And then on a monthly basis, we have said the amount of net production we think we can add. Because what we want to do, is we want to be accountable to the public if these numbers change. And we will, kind of, add and delete as we drill new wells this year.

But I think at the bottom -- and again, I don’t know if you can read this -- but, the net production we think will come on is right at 39 million a day. And our net interest in all of that is a 29 percent interest.

The reason I bring that up is -- we don't own 100 percent interest of these wells, we don't even own 50 percent, kind of as a risk tool. We usually own anywhere from 30 to 40 percent working interest, and we'll net it out and we will own, typically, about a 30 percent net interest in all of these wells.

And you can see that, in 2004, what we will do, is instead of spending 60 million we’ll spend 67 million. Instead of drilling 18 wells we’ll drill 24 of those. And what we want to do in '04, is kind of blend it.

We will blend it with the 40,000 acres, which is the Ship Shoal 113 area. Where we have seven production facilities. We should keep a rig busy there this year. We’ve drilled about four wells already that have been successful, and no bad ones. Then we’ll drill five deeper shaft wells, which, we kind of blend those in, which we just started doing that this time last year.

And then we will continue to drill Ship Shoal 109, 110, wells, that are 12,000 feet wells.

We should have a better blend of properties and a better risk curve on our properties, too. And as we said in the conference call, we started off, really, gangbusters this year in our offshore program.

Okay, if you look at the timing of your 10 million budget, are you all expecting to be pretty consistent throughout the year, in terms of timing?

Pretty much, Ron, spent evenly over the year,

Okay, let me let someone else jump in. Thanks.

Gary Stomberg (ph), Bear Stearns.

Good morning. Some of my questions were answered. The 19 wells in the Gulf -- is that 39 Mcf a day, is that an IP? And what do you think first-year decline is on that?

You usually have about a 20 -- these will probably have a 20, 25 percent decline -- and that is normal in that area. I think the difference is, if you'll notice, most of these wells have anywhere from 5 to 9 (indiscernible) behind (indiscernible). And what we always do is we start at the bottom of the well and complete it from the bottom to the top. So a lot of this production, we think, we can maintain with the completing (indiscernible) in the upper pipe. But that is, that’s an initial rate. And it will drop off once it comes on, which is normal.

Okay. And then just a modeling question. On the differentials compared with (indiscernible) for oil and gas. Fourth quarter looked a little bit light on the gas side. Where should we model your oil and gas price realizations versus Nymax (ph) in '04?

Well, I think we averaged just slightly above the Nymax price in '03. It does fluctuate a little bit, kind of based on what may be happening, especially if you compare Houston Ship Channel (ph), which we have a lot of gas in that markets to Henry Hub (ph) and sometimes the differential is tight, sometimes it widens up.

So there is no perfect answer, because if the situations can change between those two markets. But, we would still see this very tight to Henry Hub, with maybe a slight up to 5 cents premium.

That is on gas?

On gas.

And oil? Flat as well, do you think?

No, oil, typically -- well, if you're looking at the Nymax Contract versus a posting number, we typically are like $1 under a Nymax type contract price on oil.

In you're still unhedged?

We are still unhedged at this time.

Any plans to put any hedging in with these high prices?

No.

Okay. And then final question on the cost front -- I know there is a lot of production coming on. Can we expect unit -- LOE (ph) and G&A to come down in '04 on average?

After the -- yes, the first quarter, I'd see it being real similar to the fourth, because it is a lot of the same production. But as the new production comes on, we do expect to see some of the (indiscernible) cost come down. Almost all the new production is in federal waters, so there is no severance tax, so that is a plus. And then you'll just have more volumes, which will help lower the other cost also.

Do you think for LOE, if we are using 95 cents, do think that is too low or is that achievable for '04?

I would start out -- I would just say $1.00 until you actually get into those numbers and see how they come out exactly. I think $1.00 is pretty reasonable number.

Part of it is based on where the price is, the lower price, the severance taxes, and all that part come down, almost proportionately. But if you are assuming a 5 dollar gas price, where kind of the market is, I think $1.00 is a real safe assumption.

Okay. Great. Thank you very much.

Brad Beago, Credit Lyonnais.

Good morning, guys. Congratulations on a great year, I don't think anyone out there can boast these kind of drilling success that you guys did this year.

Thank you.

A couple of questions on your reserves. I'm curious what you have booked for South Pelto that will be coming online? And I was wondering if you could kind of breakdown Gulf of Mexico into behind pipe and PUD? I guess there's is a lot of concern out there about Gulf of Mexico PUDs, but I understand most of your reserves are probably behind pipe. I wondered if you have that breakdown, Roland?

I'm not sure if we have that in front of us, Brad, I think generally you're right, we do have a lot of behind pipe the Gulf of Mexico, because you have, typically, you have wells that have, as you see a lot of our press releases, 4 or 5, 6 different sands. And you'll produce one (indiscernible). Of course, those individual zones, may have a short life, but then as you go up to the next one, then you kind of start over again.

And you really start from the bottom up. So that is a lot where a lot of reserves are.

The only place where we have some undeveloped reserves in the Gulf is in -- there's some in the Ship Shoal 113 unit, because of the nature of some of those older, shallower reservoirs. But that is not area that we have a whole lot of undeveloped reserves booked at.

The one thing, Brad, you know -- this year and probably last year, I'm not sure -- under SEC guidelines, you have to test your wells before you can book reserves. So the 19 wells that we have, (indiscernible) we're waiting on connections, all the reserves booked in those wells of course are tested. I think that is a little different than has been a couple years ago, I know.

The other thing, I think, if you look at our reserve base, we have been drilling in the same area for probably nine years, in the Gulf of Mexico. I know from 1998 through the end of last year, I think we had drilled 98 wells in (indiscernible) four areas (ph), South Pelto, South Tim (ph), Ship Shoal, and the vast majority of those wells, and we've had about a 78 percent success rate.

So, I think when you look at the reserves, you have got to say -- are you in a international play (ph), are you in a place that nobody cares if you have reserves or not? What kind of prices do you have and are they kind of in your backyard, you know, an area that has been drilled in since the '50s. And that is kind of where we are.

We do have, Brad, at the end of the year, a kind of unusual amount of reserves in the Gulf and the developed but nonproducing category. Which relates to these wells that are not hooked up yet.

Yes, our reserve life is about fourteen years. But, when you add to 19 wells that are waiting on sales connections, when you put those online, the reserve life will drop probably, Brad, to about twelve years.

11 or 12.

Yes, 11 -- maybe 11.

Or maybe further. Yes. But it depends on if you add new stuff also. In the future.

Okay, I was wondering if you wanted to say a couple of words about your inventory in the Gulf? I mean, you guys did a good job of growing through the drill bit this year. And my question kind of is -- is it repeatable this next year, or is it time to look for acquisitions to increase that inventory?

That is a good question. I think what we have done is -- you know, if you have a failure in an area, it seems like it all fails and the whole area is bad and you sell it.

But if you have repeated success, which we have had in the Gulf, in the shallow area -- 10 to 40 feet of water -- particularly in the Ship Shoal, South Tim, South Pelto area. What we have been able to do is we have been able to add new prospects.

I know last year we increased our acreage through the (indiscernible) sale in March by about 60,000 acres. And then we were able to buy from Murphy and Conoco Philips (ph) this last year -- last two years -- 40,000 acres in what we call the Ship Shoal 113 area and we have twelve prospects there.

So really what is happening, we drilled a deeper wells. We drilled several wells that are deeper than 16,000 feet in 2003. And now we have got a nice inventory of your deeper prospects -- the deeper share prospects.

So our inventory has actually improved, and our success has improved. Again, we were 18 out of 18 last year in the Gulf, and that is not repeatable, in my opinion, at all. We have historically from '98 on, had about a 78 percent success rate. And that is above average. So we don't ever count on having (indiscernible) successful in the Gulf by any means.

But as far as our attitude toward growing in the Gulf, I think that the inventory that we have and we've proven up -- we will grow in the Gulf of Mexico. And I think we came grow exponentially.

We are already four for four, maybe five for five this year alone. And it is just the middle of February. Last year we kept two rigs busy, and then we ended up with four rigs in the Gulf, and now we've got four rigs in the Gulf. We have eight rigs busy overall.

So not only have we added more prospects, we've added more rigs to drill the prospects. Because service costs are relatively low. And as you know, commodity prices are high. So, we think we should drill those wells.

As far as acquisitions, we had mentioned that -- we are in New York today -- that we -- today is the first day of a proposed offering of the new senior notes. We were here a couple of weeks ago with S&P and Moodies (ph). And in fact, I don't know if the equity on it would (indiscernible) but S&P came out this last week and gave us a whole knock upgrade. We went to -- (indiscernible) that would be minus from a B+. Which (indiscernible) incredible advanced in the environment that we were in for them to look at our credit quality and give us a full upgrade. (technical difficulty)

What we had told them, and what we told the new perspective bond buyers today, is that we are not interested in increasing our debt to cap, we want to decrease it. This time last year, Brad, we had about a 62, maybe 64 percent debt to cap, in relative earnings. We paid down our debt about $60 million, and today we have a 51 percent debt to cap. We really, our goal is to get it at 50 percent. Our real goal is to get it at 45 percent. And in a perfect world, I would like to have it at 35 percent. I think if we were to go all through all this year and '05 with the same type success we had last year, and we didn't buy anything of any size, we would probably hit that 35 percent number.

But -- if you look at any acquisitions -- I think that we would not look at the Gulf of Mexico. I think there is a 1 percent chance we would ever buy anything in the Gulf, because our inventory has such great quality to it, there's a lot of depth to it, and we need to drill what we have on our books as far as prospects there.

I think if we look at buying anything it would be onshore, it would be in a core area, there would be natural gas reserves and have long live. It would have to have a 3,4,5 year chilling program with it, and we would have to operate it.

And the reason led look for that type of an acquisition is because we are traded as on onshore Company. Because 65 percent of our production and reserves are onshore. 35 percent are off, and well, we want to keep it that way.

That is a one reason in 2001 when commodity prices crashed we were able to buy that Debex (ph) assets for 98 cents per MCFE (ph), which were long life gas reserves onshore. Now, we didn't operate the major field, which is Gilmer, so we're not interested in buying something we do not operate.

But if we did buy that, then yes, we think that would kind of counterbalance our growth in the Gulf. But, we would add a significant equity piece if we bought something like that, and we would present it to the public and say, "Here is why we're doing it," and you would know all about.

But our business plan in 2004 is similar to that in 2003, and it is a weird plan compared to the public, in that we are not saying we are going out and buying things. We are saying that we think we can repeat 2003 in 2004 because of several reasons.

We have a better prospect inventory, in the Gulf, than we have ever had. We have never drilled a deeper well in Gulf this time next year. And then now we've drilled several of them. We did not own the remaining interest, (technical difficulty) we trying to buy (technical difficulty) Ship Shoal 113 from Conoco Philips (ph). We now have that and we have reprocessed the data. And we have had 3 or 4 successful wells there, which will be hooked up to sales within two months after completion.

You know, we did not have the 3-D seismic in the robin area (ph) onshore, and I think we'll have that this year, and we will drill a well or two there. And I think we can extend the play in the Ross (ph) area, because we don't have 3-D seismic to the south there.

And if you look at our debt, I mean, we've gone from 62 percent to 51 percent debt to cap. And if you look at the amount of money we will spend for CapEx, we are going to increase it by 27 percent to $110 million. And I think we can reduce the cost of our funds materially. By calling these bonds May 1st of '04.

So, I don't know, we always look, I say we shop all the time, but we very seldom buy. And if we were to buy anything in '04, I mean, we realize that we would have to pay for behind pipe reserves,. And, you know, it is a very expensive market to buy things in. But even with that said, we do look all the time, but we just -- we very rarely buy.

Okay. Well, great. Thanks a lot for all that wrap-up, Jay, I appreciate it.

Van Levy of CIBC World Markets.

Gentlemen, how are you? Good. A couple of questions. Can you give us where your guesstimates are on your exit rates for the second quarter and by the end of the year?

On a production basis, yes. We would look at production just on a -- in the second quarter -- being close to the 140 million a day type area. And maybe by the end of the year, maybe 145.

That kind of factors in the new well coming online. And then of course, obviously, building and decline, in all that. That is initial production rate shown on that chart.

And Roland, let me ask you this -- are there any particular concentrations -- if I was to look at, tried to handicap kind of a risk, a risk concentration, you know -- 18, 19 wells -- looks like it's pretty spread. But in terms of working interest or productive ability of the well, is there any major risk in there?

Well, obviously, the risk is they've never -- it's all-new production. So once they are on, you're going to have -- know a lot more about them.

A lot of these are new fields. Probably the Ship Shoal 113 area is much more predictable, because it is a, more of a developmental place. So that -- I would say -- is the lowest risk.

A lot of the areas we have seen some initial brief task, but I think, I would think, that there would not be any kind of unusual concentration or rest (ph) in the different projects. So they are spread out like you see (ph) to a lot of different wells. We're not looking at one well to deliver all this production.

Okay. In terms of the Gulf of Mexico -- can you give us a sense of what your historic funding (ph) costs have been, maybe what your DD&A rate is there?

Also, as these ramp up, toward the end of the year, would you expect -- I think you showed $1.34 as your lifting cost in the Gulf of Mexico -- would you expect that to come down? If so, how much? And then finally, maybe Jay could speak to the risk of the program 2004 versus 2003? Maybe -- a few more wells going deeper, etc.? Or does it look essentially the same in terms of a risk profile?

If you look at the finding (ph) costs in the Gulf of Mexico, especially if you look at what is the DD&A in the area, I think it -- it has been $1.90 to $2.00, has been historic, if you take all in, everything that has been involved in the Gulf of Mexico.

That is probably a good number going forward. We might be able to bring that down a little, if you continue to have high success rates.

On lifting cost, we will -- I think, we will see improvement in some of the lifting cost in the Gulf of Mexico, starting in the second quarter with the new production coming online. One, because a lot of it won't have any severance taxes, because it is all in federal waters.

So that is -- and then you'll just have higher volume wells, should fare, the beginning of their life, fairly well.

The lifting costs were higher in the fourth quarter because of acquiring additional interest in Ship Shoal 113, and it's on the very beginning -- it is a very big operation, and the production levels do cover the operating costs. But as we drill these wells, we'll really improve the operating costs there.

And those -- you know, with the first four wells have been successful -- and now they are hooking those up. So you really didn't see any benefit from any new production, really, for our work there. Until now in January.

Van, on the risk profile -- if you go through the four areas -- number one, we don't plan on drilling any wells outside of our core areas. Not in our CapEx budget. East Texas, as you know, I think since like 1995, we drilled 146 wells. We have hit 92 percent of those. We pulled it back -- last year we only drilled -- we spent $6 million and we drilled, like, five wells and we hit four of them.

Those wells, I mean -- 92 percent success rates is normal there. We will spend another million dollars, this year we will spend 7 million, drill seven wells. And I would think that we would have similar results as we have had for the last eight years.

In South Texas, last year we spent 15 million drilling 13 wells -- we hit nine of them. This year, we're going to spend the same amount money, but we're going to spread it over 15 wells. And five of those wells will back at Ball Ranch, which last year, six of them were at Ball Ranch. And that (indiscernible) about 12,700 feet (ph). It's about a 21,000 acre ranch that has 38 square miles of 3D on it, so we should, I would think that we would have similar results there.

In the Gulf of Mexico, that program, as you know, is really not driven by the prospects that we have, it is driven by the commodity price. Because we have had anywhere from two rigs to four rigs -- even one rig -- on a monthly basis, active in that area. And that really depends upon commodity prices.

Two years ago in 2001, I think we kept one rig busy -- we drilled 11 wells, hit nine of them. Last year, of course, we kept two rigs and then ended up with four rigs. But last year we spent $60 million, we drilled 18 wells, we hit 18 of them. This year, I think the risk profile is a lot better.

We are going to spend 7 million more, so 67 million, but we are going to drill six more wells -- we are going to drill 24 wells this year. And as we said, the Ship Shoal 113 area, that 40,000 acres -- we are going to blend in some of that production, which is your 19 to 10,000 foot production -- the vertical wells. We are going to blend that in with some deeper wells, five deeper wells, and you complement that (indiscernible) area and the South Tim and Ship Shoal 109, 110 wells. And those are about 12,000 foot wells.

So I think that will be comparable. I think it will be a safer profile. Now, again, I don't think that we'll have 100 percent success, we'll probably drop back to the 78 percent, would be our guess. Although we are, I guess, for 4 for 4 as of right now. So we have got to get started on that.

And then Southeast Texas, I guess would be the question mark. We have historically -- we've drilled at least 22 wells based on 3-D seismic and probably a lot more that, really.

We have had an 86 percent success rate in the AA, the Ross type area. We have drilled the Hamman #1, the Hamman #2, the Collins #1 and #2, and the Hamman #3. So we have drilled five wells, and we have hit four out of five. So that is a 80 percent success rate there.

What our plan is in '04 -- is to take this seismic, which our geophysicists (ph) and geologists are excellent in creating organic growth. But we're going to take seismic and we are going to see if we cannot extend the reservoir that we think we have in the Ross area to the South and maybe to the Southeast. Because we do own acreage around there to the South. And that is the tail end of our existing 3-D seismic line.

And at the same time, we are going to look at that the what we call the Robin (ph) prospect, which is a 4,000 acre prospect. And we will have the ARCO well logged (ph) that we drilled in 81, we'll have the seismic on the (indiscernible) well that was drilled. And we do have the 2-D seismic. So, we will drill six wells there, four or five or those will be kind of in the Ross area, and one or two will be in the Robin area.

I think if we're successful there, that could be a big impact on our reserves in '04. And if we are not, I mean we have not booked any reserves there anyhow.

Another one -- we drilled the Ross area, we told the world that in 2002 we would drill one wildcat well, and that happened to be the Hamman #1, and we capped it at 20 million a day production for over year. So, hopefully we will be successful on this robin (indiscernible).

I guess that big question (indiscernible) Van -- is whether we will own all of it, or sell it down like we have done at the AA or the Ross area. And our inclination right now is that if the 3D looks good, and we see (indiscernible), that we will end up owning all of that well when we drill it. And that's a $3.4 million dry hole cost for that well. That's about a 19,000 ft. well.

Okay. Couple of mechanical questions. Roland, could you give us the deferred tax and the production tax amount for the fourth quarter?

Sure. On the deferred taxes, the amount of taxes that were deferred was $2.3 million, and we did have some current taxes that we booked in the fourth quarter.

Do have that (indiscernible) -- I hate to be pedantic -- but, do you have that to four digits? (indiscernible) my model? Same with production tax?

And then, Jay, I would like you to comment, last question, I would like you to comment on reserve integrity -- it has been a big issue -- within the industry. It is probably going to be a lot bigger going forward. Maybe you could talk about the performance issues that you had? And looking forward, how you're monitoring that, and whether we are going to -- are there any other areas that are of high-risk that we should be concerned about?

Let me give you, Van, the deferred taxes for the year. And then I will let you do the math. It is 27 -- 27,982,000 for the whole year. And then as far as production taxes, for the quarter, that was 2.2 million of the total $12 million and lifting cost --

Okay.

Actually, we're -- production taxes are a little off in the fourth quarter because of the oil increase, and there is just higher state taxes, I guess, on oil than gas. As a percentage of value.

Okay. Thanks.

On the reserves, Van, again, that is a good question. As you know, we're successful efforts, and if we drill a well and it is bad, we write it off. We are not (indiscernible), we don't have any closets to hide that stuff in.

And every quarter, of course, we looked at the well performance, and we look at the cost structure. But you kind of put all in a box at the end of every year. And if we recognize we have an area that is not performing properly, then, you know, instead of putting all these problems in the closet, and then opening the closet one day and getting killed, we say --here is a problem that we have got.

And when we do that, what we try to do in our reserves -- if we stay in the same area, and so hopefully we understand them. We've used (indiscernible) forever, on our big discovery in the Gulf we have brought Needelan (ph) and Soeul (ph), so we are trying to get a value from them which is a consistent value in our deep wells.

But the biggest problem we had was an area in West Camron (ph) which we did not operate, it was something we bought in '93 when we bought Stanford (ph) -- it was very profitable.

But we don't operate it now and the cost went up, and the reserve base, we lowered those, and so we said that the value is not there. So we wrote it off. And that is -- you know, we found that at year-end, and we cleaned it up, and it is over with. If we had anything else out there, we would do the same thing to it.

Okay. Thank you very much.

Ray Deacon with First Albany.

Yes. Good morning guys. I was wondering if you could just elaborate a little bit more on the deep shelf program where those five wells are likely to be this year?

Okay, Ray. We are actually, because of the discoveries, of course, last year at South Pelto 22 and 25, there is additional drilling in both of those blocks. And those are some of those deep wells. Of course, we will be working with -- we have got partners at all those projects.

You, know, like we said -- at both of those, there are is a lot of faulting going on. So we feel like just, we have been able to add reserves in each fault that we tested, like in 22, and there are still several (ph) more faults to test going across the block. 25 looks just like that. So it's going to take more those wells to continue to step out.

And then we have got a few, a couple of ideas, that kind of take the same type of seismic, the signature that discovered these properties on some of our other properties in that same area, where we are -- will probably look at a couple of deep wells to try to extend that over. It is pretty much in the same area, and more of the same stuff we did last year.

Great. So it sounds like the majority of the five wells could result in reserve adds rather than development wells?

Right. We don't have any development wells like that. We have no development wells like that out there. The one development well we drilled at South Pelto 22, we have drilled that, and actually we used it to also extend the reservoir by taking part of it into another fault lot. But they should be -- a lot of those should be reserve additive. If they work.

Okay. And as far as Southeast Texas goes, are you -- it sounds like the timing has been pushed off a little bit. I was thinking something like May, June, would be the first well there. Is it just the seismic taking longer? Maybe it is sounds like some permitting issues?

Well, what we said on that, I mean, actually we hope that occurs. But in our planning, and in our models, we have just said -- let's assume it takes place in fourth quarter. That is just a -- it's a more conservative way to present it. (indiscernible) slowed down any on that, we would like to drill it tomorrow.

There two big things that have to be accomplished. One is the, of course, you want all the seismic in to get in-house, to look at it. And then secondly, we have not finished the permitting process either. So those two things are out there that are factors. So we are trying to leave enough time for all of that to happen.

Well, the one thing we don't want to do, Ray, is to rush and drill a well, you know, 30, 60, 90 days sooner than we should. If it is that big of an impact well possibly. Because, I mean, (indiscernible) a dry hole, well, you know, our plans right now would be -- we'll drill another one. Because you don't condemn a whole plate with one dry hole. But you can get a first well that is really good, then you need to do that. So we are just -- we are cautious not to rush, even though that -- you know, we think (indiscernible) happen earlier than that.

Okay. Got it. And, actually, going back to the Gulf -- did you get any kind of -- I assume that South Pelto 22 and 25, you did not get to book many reserves there since it is not on production yet -- but, you know, did they give you any kind of probables or possibles number?

Well, yeah, we got those, we don't ever really talk about those. The probables and possibles. We were able to book some reserves with, initial, just the wells that were drill. You had the two wells, and then the well came into this year. The third well there is actually a '04 kind of event.

So, they are nice wells and additions, but we certainly did not try to book a large amount of reserves that could be disproved with drilling in the future.

Right.

I think that goes back to reserve integrity that Van was asking about. We looked, you know, four or five fault blocks in 22, and we had tested a couple of those. In the reserves we booked (indiscernible) just pertained to those fault blocks. And then nothing that we have not drilled or tested.

Okay.

Same way with 25. We booked very few reserves on 25.

Okay. It got it.

And has less control, probably, than 22 does. As far as once (indiscernible) there, until the second well is drilled.

Okay. Got it. Is the hope in East Texas reinvigorating activity levels there instead of seeing a decline in '04 -- do you hope that will be sort of flatter, is that going to become a growth area again?

Well, we had 11 percent decline last year, because we did not spend a dollar there. And there's really three reasons we didn't. First of all, we really had better places to spend it -- you know, our other three areas which provide higher cash flow.

We knew the acreage rate was not going away (indiscernible) production. So you don't lose it if you don't drill it. And you know, one of our corporate goals last year was to materially paydown our debt to position ourselves to have to get rid of the bonds that were in New York to date, you know, working on.

Right.

I think what we have got in -- as far as the drilling budget in '04 -- although we have a lot of locations, what you're going to find is you are going to accelerate your production, your finding costs would up, your production would go up, it would be very, very profitable. But, you know, we said if we had 110 (indiscernible) of CapEx, and we have plenty of places to spend it, why, again, why don't we spend it somewhere else.

Basically what we have in our current business plan, Ray, is a very similar to last year. We are not spending enough money there to expect production to -- we would expect another 10 percent decline in that region based on the current budget. And that's factored in.

Because we wanted to do one more a year. We want to get our balance sheet to our target. And that is what we are going to focus on, versus drilling a lot of the development wells there.

But then after that is done, then we might go back and revisit that. That is our most price-sensitive area too. So if we're going to really invest a lot of capital on accelerating that development, that might be an area we should consider, you know, supporting with hedges. Because it's really has to have higher prices for those undeveloped wells in East Texas, to really make a return on investment.

They do not make the return on investment if you drill on them gases below -- like, $3.00. If those come into our budget in a big way, then we probably have to look back at how we are doing that. Because our other projects that we're doing now are not (technical difficulty) price-sensitive like those.

Okay. And just one more question -- I want to make sure I'm doing the math right here -- it looks like the payout on the 20 million you need to spend to call the bonds is probably going to be about a year and a half -- it does that sound right?

I think that is about right --

It is a little over 4 million a quarter.

Right.

Okay. Thanks.

Pavel Mockanoff (ph) of Raymond James.

Hi. Good morning. Question for Roland about your debt. Do have a specific target for year-end debt to cap? Or your aggregate debt amount? Or are you just going to sort of judge that according to your cash flows for the year?

Well we do have a corporate goal -- we want to be below 45 percent. That is our current goal. And we think we can get there with our business plan this year. We think everything is in line to do that just through using part of the cash flow to pay down debt. So that's kind of how -- we do look at it that way. We said -- what is our -- we want to get our debt to book capitalization (ph) as good or better than the peers.

At the same time we feel like we can increase production by 10 to 15 percent through the drill bit.

Right.

It is a similar plan to last year, and we think that is the right conservative business plan for the Company. Again, we think it's the best way to add value, instead of focusing just purely on production growth, if you look at production growth, maybe adjusted for debt reduction, we think that there we're delivering kind of a double-digit growth, if you take both factors into account. And we think that is the way you really measure value is how your (indiscernible) production after adjusted for -- are you increasing or decreasing debt?

Understood.

Ron Mills of Johnson Rice.

Roland, this is the easy one of the day. On your G&A, was just a little higher in the fourth quarter, I know you opened up the Houston office and maybe even added some (indiscernible), but what is a good run rate for '04? Did the fourth quarter include any kind of accruals?

Well, the fourth quarter always, you know, you maybe have some extra cost, like we do every year, just because you have all your -- a lot of projects -- you have all your year-end stuff. That we would look at -- I mean, our G&A has been trending to go up a little bit, mainly because we are staffing that technically. But we think that is what we need to do. Like up in the Houston office.

And we are using about a $2 million kind of per quarter number going forward. I think that is a good number.

So it is a -- in prior years, we really focused on being the very, very lowest cost operator, but I think what we have done is we've become more of an expiration Company. We don't put any of our G&A into expiration expense, which maybe that is a little different than some of the other Companies. So, all of our overhead is shown in that number. We do not capitalize any.

Right.

But we are starting to maybe -- just, we continue to add to that effort, as the Company gets larger. And hopefully we will grow our production at the same kind of rate, so we keep the relationships better than the peer average is likely to have.

Alright. Thank you, guys.

Mr. Allison, at this time I show no further questions.

I want to thank everyone that started out 1:15 ago -- it was a good conference call. And a great year. Thank you.

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