Comstock Resources Inc (CRK) 2002 Q4 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to the Comstock Resources 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 will now turn the call over to Mr. Jay Allison. Mr. Allison, you may begin.

Thank you. Good morning, everyone. Welcome to Comstock Resources fourth quarter 2002 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 will find a presentation entitled fourth quarter 2002 results. To change the page, click on the arrow on the page.

I am Jay Allison, president of Comstock, and with me this morning is Roland Burns, chief financial officer and Mike Taylor (ph), vice president of corporate development, who will help answer questions.

With this call, I will review our fourth quarter and 2002 financial results, as well as the result of our 2002 drilling program. We will also discuss our announcement today that we will be restating our prior-year financial statements for 1998 through 2001. Our discussion today will include forward-looking statements within the meaning of the securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct.

Page 2. Our off shore exploration venture. First let's discuss our announcement that we will restate our financial statements for years 1998 through 2001. The restatement is due to the recharacterization of certain advances made by us to our partner under our joint exploration venture in the Gulf of Mexico with Bois d'Arc (ph) Offshore Limited. Under the venture, we make advances to Bois d'Arc to fund the acquisition of off shore leases and seismic data. They generate drilling prospects on the leases and we're entitled to 40% interest on any prospect generated. The other 60% is retained by Bois d'Arc or sold to third parties. Upon sale of a prospect, we are reimbursed 100% of the cost advanced for leases, and we are paid a fee which allows us to recover the amounts advanced for seismic.

Historically, we have capitalized the advances made to acquire leases in seismic and offset these costs with the reimbursements received from the sale of the prospects. Our new independent auditors are re-auditing our 2000 and 2001 financial statements as these financial statements had previously been audited with Arthur Andersen, which is no longer reissuing its audit reports. In connection with the re-audit, we are informed by our new auditors that the method of accounting for the advances which were used to acquire seismic data was not appropriate. They advised that any unreimbursed advances related to seismic data acquisition on the balance sheet should be charged to expiration expense with the future reimbursements of such cost to be offset against future exploration expense.

Page 3, restatement of prior years. The impact changing the accounting treatment of the seismic advances is a reduction to previously reported net income by$390,000 in 1998, $270,000 in 1999, $203,000 in2000 and 1.6 million in 2001. The effect on earnings per share was one cent reduction to 1998, '99, and 2000 and a 4-cent reduction in 2001 for a total of 7cents over the four years impacted. There was no significant impact with using the new accounting treatment on the previously reported financial results for the first three quarters of 2002.

Page 4. Off shore prospect inventory. The advances for seismic were written off only because of technical accounting rules, not because they are not expected to be fully recovered in the future. As of the end of 2002, there was an inventory of 42 drilling prospects that have been developed under the venture with our reserve potential of 721 billion cubic feet equivalent. Over 100,000 acres in the Gulf of Mexico have been leased or acquired under the venture. We estimate that just these prospects alone would generate$8 million in future fees. They would be used to repay the 4.1 million in unreimbursed seismic advance that were written off in the restatement.

Page 5. 2002 highlights. Now we would like to discuss our financial results for the fourth quarter of 2002 and the year-ended December 31st, 2002. With improved natural gas prices in the fourth quarter, we reported $9.5 million in net income from continuing operations, or 29 cents per share. A $7.7 million severance tax refund and a $2.1 million write-off of a dry hole in southeast Texas were other significant factors shaping the fourth quarter results. Our production was up 11% in 2002,mostly due to the Devax (ph)acquisition. Production in the last half of 2002 decreased from our first half levels because of disruptions in the Gulf related to the hurricane activity.

We had excellent results in our drilling program in 2002,where we have had 41 successes out of 47 wells drilled in 2002, giving us an 87% success rate in2002. The successful drilling program combined with our acquisition activity in 2002 resulted in our finding cost averaging 90 cents per MCFE. The highlight of 2002's drilling program was the successful Hammond (ph) number one discovery that was put on production October 18th of 2002, which has averaged 18.8 million cubic feet equivalent per day since inception and we operate it on a 58%working interest end.

Page 6. Revenues. Revenues in the fourth quarter of 2002 were more than double our revenues in the fourth quarter of 2001: Our revenues increased by 106% to $41.89 million from $24.2 million. Higher production, much higher oil and gas prices and the $7.7 million refund of severance refunds account for the increase. The severance tax refund resulted from a change in the classification of our double A wellsfield and relates to the period 1996 to 2001.

For all of 2002, our revenues totaled$150.2 million, a decrease of 16.7 million, or 10%from revenues of $166.8 million for 2001. Higher production levels in 2002 were offset by lower natural gas prices.

Page 7, EBITDAX. Earnings before earnings, taxes, depreciation, amortization and exploration expense or EBITDAX increased 158% in the fourth quarter to$38.7 million as compared to $15 million in the fourth quarter of 2001. EBITDAX for the fiscal year ended 2002 totaled$109.4 million, down 17% from $131.4 million in2001.

Page 8, cash flow. Operating cash flow. Our cash flow from operations in the fourth quarter of last year increased to $31.1 million, up 140% from the $135 million in the fourth quarter of 2001. Operating cash flow for all of 2002 was$79.9 million, down 28% from $110.1 million for2001. earnings. We reported a 334% increase in net income from continuing operations of $9.5 million in the fourth quarter of 2002 as compared to a net loss of 4.1 million for the fourth quarter of 2001.

For the year-ended 2002,our net income from continuing operations of$11 million was down 67% as compared to the$32.9 million in profits we had in 2001. We had29 cents in earnings per share in the fourth quarter of last year, as compared to a loss of 11cents in 2001's last quarter. We made 37 cents per share for all of 2002 as compared to earnings per share of $1 in 2001. We also had a$1.1 million loss or 4 cents per share from discontinued operations, which represent the sale of certain marginal south Texas properties which we sold in the first and second quarters.

Page 10. Production. Production in the fourth quarter of last year averaged 110 million cubic feet equivalent per day, which represents a 13%increase from 2001's fourth quarter and up slightly from 2002's third quarter. We averaged 33 million cubic feet equivalent per day in east Texas,, 31 million cubic feet equivalent per day in our Gulf of Mexico region, and 14 million cubic feet equivalent per day in south Texas and other regions during the fourth quarter. Our production in the Gulf continued to be hampered in the fourth quarter by the hurricane activity in September and October of last year. We were shut in for part of October, and our south Pelto1 (ph) property remained offline for all of October and much of November, waiting repairs to a production barge that was damaged by the storms.

We had a gain in production in our southeast Texas region from the Hammond well which came online about midway fourth quarter. We expect a significant gain in the Gulf of Mexico region in the first quarter of 2003 of over10 million cubic feet equivalent per day due to the return of pre-hurricane production levels combined with new production from several wells coming online that were drilled in 2002. Additional gains were expected in southeast Texas and south Texas from new wells being put online. For all of 2002, we averaged 112 million cubic feet equivalent per day in production, up 11% from 2001's production level of 101 million cubic feet equivalent per day of production.

Page 11. Average oil prices. Our average oil price increased 40% in the last quarter of 2002 to$27.26 as compared to $19.48 in 2001's fourth quarter. For all of 2002, we averaged $24.95, a decrease of 2% from 2001's average price of --$25.46.

Page 12. Average gas price. Gas prices were up substantially in the fourth quarter of2002 as compared to 2001's fourth quarter. Our average realized gas price was $4.07 or 63% higher than fourth quarter 2001 average gas price of$2.49. For all of 2002, our gas price averaged$3.30, 28% lower than our average price of $4.58in 2002. Page 13. Cost per unit of production in the fourth quarter. Our lifting costs per Mcfe increased by 9 cents in the fourth quarter of last year to 89 cents from 80 cents in 2001. Our G&A expense for Mcfe averaged 21 cents in the fourth quarter of 2002, the same as the fourth quarter of2001. Depreciation, depletion and amortization averaged $1.35, the same rate that we had in 2001.

Page 14. Annual cost per unit of production. Our lifting cost per Mcfe produced for all of 2002decreased by 4 cents to 82 cents from 86 cents in2001. Our G&A expense for 2002 averaged 12 cents, the same as 2001. D and A averaged $1.29, 1 cent higher than 2001's rate of $1.28.

Page 15. Cash margin. Due to higher gas prices in the fourth quarter, our cash margin per unit of production increased $1.41 to $3.06 per Mcfe as compared to$1.65 in 2001's last quarter. Our cash margin in all of 2002 dropped $1 to $2.52 per Mcfe from$3.52 per Mcfe in 2001, due to the $1.28 decrease in our average natural gas price. Page 16. Capital expenditures. In 2002, we made$84.2 million in capital expenditures and achieved an all-end finding cost of 90 cents per Mcfe.

We spent $23.1 million to drill 27 developmental wells, 26 of which were successful. We spent an additional $7.4 million for work-overs and recompletions, and $4.9 million was spent for offshore production facilities. We spent $37.4 million on our exploration program, which was over half of our total drilling expenditures. $31.1 million was spent to drill 20 exploratory wells. 15 were successful, five were dry, giving us a 75% success rate in 2002. $6.3 million was spent for exploratory acreage and seismic data, and we also spent 11.4 million on acquisitions. The most significant of the acquisitions was the purchase of a 45% working interest in a Shipsho (ph) 113 unit from Murphy. The acquisition included interest and over 40,000 acres and six production platforms.

Page 17. Our balance sheet. At the end of 2002, we had $366 million in total debt, 146 million outstanding under our new bank credit facility which had a $240 million borrowing base, giving us $94 million available under our credit facility. We ended the year with$226 million of book equity at the end of the quarter. Debt was 62% at the end of the year. We expect to see this ratio fall to the mid50% level in 2003 as we continue to pay down debt with a higher cash flow resulting from the improved natural gas prices. We paid down$18 million in debt in the second half of 2002.

Page 18. East Texas, north Louisiana regional results. Last year we spent $18 million drilling18 wells, seven net wells. 17 of the 18 wells were successful with one exploratory dry hole drilled in north Louisiana. 15 of these wells were in the Gilmer (ph) field we acquired in the Devax acquisition. We tested all but one at an average rate of 1.8 million cubic feet per day per well. This year we plan to spend around$8 million in this region for developmental drilling and recompletions.

Page 19. SoutheastTexas region. We spent $5 million in this region in 2002 drilling the successful Hammond exploratory prospect. Approximately 1.5 miles south of the AA wellsfield and the two offset wells, the Collins (ph) number one well and the VastarFee (ph) number two well. The Hammond number one well has averaged 18.8 million cubic feet of gas equivalent per day since it was put on production on October 18th. The VastarFee number two was not successful and accounted for much of the2.1 million exploratory cost in the fourth quarter. The Collins number one was drilled to a depth of 14,950 feet, and discovered approximately 41 net feet of pay in the Woodbine (ph) formation. Completion operations on this well are currently underway. We're on a 58% working interest and operate all of these wells.

We plan to spend$14 million in the southeast Texas region this year to drill eight wells. These wells include five wells drilled to extend the wells discovered by the Hammond and Collins discoveries, two developmental wells in the AA wellsfield, and an exploratory wildcat at the Robin (ph) prospect which is to the south of our Hammond discovery.

Page 20. South Texas region. We spent $8 million in our south Texas exploration program in 2002. We have drilled eight exploratory wells and seven of the eight wells were successful. Three of the successful wells were drilled on the Bar Ranch (ph) prospect in Kenedy County, Texas, two of these wells were tested at an average per-well initial production rate of 7.8 million cubic feet equivalent per day. We have a 20% working interest in these wells. We also had a discovery with the Stockton (ph) number one in Goliad (ph) County, Texas. We expect that to be producing at around10 million cubic feet a day. We have a 17% working interest in this well.

Other discoveries in 2002 include the Trevino (ph) number one well which tested our prospect in Zapada (ph) County and two others. We are currently completing these wells. The one dry hole was at Patterson Ranch. We have budgeted $21 million to drill 18 wells in south Texas in 2003 to build upon the successes we had in this region in 2002.

Page 21. Gulf of Mexico regional results. Our Gulf of Mexico drilling program was very successful in 2002, even though we had to cut back the number of wells drilled with lower prices we had in the first part of the year. We drilled 11 wells in the Gulf last year. We spent a total of $38 million, including 2.4 million on acquiring leases and seismic data, and $4.9 million on production platforms. Nine of the 11 wells we drilled in 2002 were successful. The remaining two wells were dry holes, which were drilled at south Tembler (ph) block 30 and south Pelto block one. Seven of the wells were completed and were tested at an average per-well rate of 8.1 million cubic feet equivalent per day. The remaining two wells are waiting on production facets.

In the fourth quarter, we made two significant discoveries in our off-shore exploration program with Bois d'Arc. Another discovery was made at south Tembler block 30with the 13928 number five well. This well was drilled to a depth of 15,800 feet, and found approximately 103 feet of net pay in nine separate reservoirs. We have a 34% working interest in this discovery well, like the 13928 number six well drilled in the second quarter of 2002 is waiting on the installation of a production platform before first production. The other discovery resulted from a sidetrack re-entry of a well in the south Tembler area. This well was tested as a dual completion at a daily rate of15.8 million cubic feet equivalent per day. This well is now on production and is expected to produce 20 million cubic feet equivalent per day. We have a 33% working interest in this discovery well.

In 2003, we have budgeted $54 million to drill 23 offshore wells.

Page 22. The outlook for this year. 2003. The outstanding results from our 2002 drilling program has set the stage for a very strong year in 2003. We expect production this year to increase somewhere between 45 and 49 Bcfe, which is an increase of 10 to 20%. We still plan to spend$100 million on our drilling program this year with over half of our budget going for high impact exploration projects. We plan to drill five wells to continue to extend the Hammond discovery area. We also have substantial upside with our multi-year inventory of drilling prospects in the Gulf of Mexico and south Texas, and lastly, with the improved natural gas prices, we should generate substantial cash flow in excess of our capital expenditures. We will utilize the extra cash flow to pay down our debt, which should substantially enhance our balance sheet by the end of 2003.

With that, I will open it up for questions.

Thank you. We will now begin the question and answer session. If you have a question, you will need to press the 1 on your touch-tone phone. You will hear an acknowledgment you've been placed in queue. If your question has been answered and you wish to remove from the queue, please press the pound sign. Your questions will be queued in the order that you are received. If you're using a speakerphone, please pick up the handset before pressing the numbers. Once again, if there are any questions, please press the 1 on your touch-tone phone.

Our first question comes from Van Levy from CIBC World Markets. Please state your question.

Good morning, Jay and Roland. How are you?

Great, Van. How are you?

Great. You guys are really bucking the trend, I think, with most of the independents that I follow. Your finding costs were down decidedly, and when I look on your cash on cash are returns, your cash flow divided by your finding cost, it's excellent, again, on a relative basis, and using that same number, 90 cents for finding costs going into 2003, or even $1 or $1.10, your cash from cash returns exceed 150%. I guess my key question is, did you just have, you know, a lucky year at90 cents or 90 to 1.10, let's call it, or can you maintain this kind of pace?

This is Jay, Van. I think if you look at our results in 2002 and you look to see what we're doing in 2003, we're really -- we're just continuing in the same core areas as to what we've done historically. We'll be in south Texas, we'll accelerate that program. I think, you know, we have an inventory where we could spend probably$70 million drilling wells in south Texas right now, so I think we have a very safe set of prospects that we'll drill this year in south Texas.

If you look at east Texas, we've only budgeted $8 million, and that's mainly recompletions in a few wells, so our success rate historically has been 92% interest. We expect that same type success in 2003. If you go to the AA wellsfield and you look at the Hammond discovery and then the Collins, if you look at our3D seismic and look at the prospects that we have in inventory, you know, we really expect the same type results in 2003 as we've had in 2002 with our developmental program now.

I think, you know, the question mark will be we're stepping out about, you know, a mile or two south from this Hammond area, and we will drill this Robin prospect, and the Robin is set up due to an Arco well drilled in1981 that had the show in this upper woodbine. So that will be our big exploration question this year in the AA wellsfield. Then I think if you go in the Gulf of Mexico and look at the 40,000 acres that we acquired from Murphy in December of 2003,in the six production facilities, we've got a dozen wells right now that we'd like to drill just in that 40,000 acres, which we operate on a 45%interest in.

We're going to wait until the third quarter because we're going to reprocess the seismic, but we've drilled 80 wells in the Gulf, Van, since 1998, and I think we fit 59 out of the 80, so we've had a 72% success rate. I just don't think, you know -- I think that the likelihood of that rate in 2003 will have continued because we're staying in the same areas we had wanted to pick up this 40,000 acres with the facilities from Murphy for quite a while, and as they were successful in drilling discoveries in deeper water, we were successful in acquiring that from them. So I think the chances of us having kind of a repeatable year in 2003, you know, we've got a really good chance to do that. I mean, you never know till it's over, but we're not deviating from the areas that we have produced these results in. I think that's what you have to look at.

Ok. And second question, again, highly economic returns, it looks like your production is expanding and you're going to pay down debt, which is to me very similar to moving the stock. I'm surprised the stock hasn't moved more in this market. In the sense of paying down debt, can you give us a sense in absolute dollars you think you could pay it down, number one, and number two, this kind of begs the question I always like to ask, you know, the hedging philosophy, where your thoughts are there.

You see where gas was $6 this morning and oil was 36.65?

Yeah, I did.

And I think if you're from Boston or New York and you're on this call, you're probably lucky to get to work. But anyhow, I'll let Roland answer this question.

What we're looking at on debt repayment is probably a target of paying down our debt by$40 million this year and potentially given the current prices, that number could, you know, be up to 60, $70 million.

And excuse me, Roland, where would that leave your bank availability?

Well, that would add -- well, I think two things. That was our bank availability. We're expecting that to increase by 10 to $20 million just with an extra view because of the reserve additions, and then whatever we pay down would add on to that too, so our bank availability which is already at 94 million could go up pretty substantially, you know this, year. But I think what's more important to us is just getting the overall balance sheet to our target, which is 50%,you know, debt to cap or below, and that's what we're focusing on. The advantage availability is just kind of a -- bank availability is a safety net in case you want to use it. We don't really plan to borrow, you know, under that facility until we really get our -- meet our goals in our balance sheet.

Your borrowing basis is somewhere around 250,is that correct?

240.

Ok.

And it's up for redetermination here in the next month or so.

We looked at the model that the banks use and forget commodity price increases from the bank base, borrowing base, we think that as Roland said, our facilities should increase by 10 or$20 million without taking the commodity price into effect. So it looks very positive.

And then your other question about hedging, last year we did have our production hedged during the summer primarily going through October. The effect of the hedging was to increase our realizations which would have been 326 per Mcfe to go 330, so it had a modest impact, but it was an important part of our strategy last year where our cash flow -- expected cash flow in the lower price environment was very close to what we really had to spend for our capital program and what we thought we needed to spend. In this case in 2003,it's not a lot different. There's a very large margin between the targeted cap-ex that we want to spend and expected cash flow in any price scenario. So I think that's a key difference between the two years, but we always continue to look at hedging, and when it's an important thing to do to meet the company's objectives, you know, we've not been shy to do it. We hedged 50% of our gas in last year's environment when we thought that everything lined up right.

Van, as you may know, we have no hedges in place for 2003, and we even had a board meeting yesterday, and we always discuss hedges, so we've left it open to consider it. And then, of course, gas hit $6 this morning. We'll see what happens.

All right, guys. Listen, congratulations. Great year, and keep it up.

Thank you, Van.

Our next question comes from Brad Beago from Credit Lyonnais.

Good morning. I guess to echo Van's sentiments, great job. It's good to see this coming on the heels of everything you guys have done. Couple of questions. One is, can you kind of color in the details on the Collins well? This is a separate fall block from the Hammond, correct? And have you booked any reserves for Collins? And maybe you could go through what you booked for the Hammond.

Yeah, Brad this, is Mike Taylor. The AA wellsfield and the step out here at Hammond, these are all strategies. We believe that the Collins is in the same field as the Hammond. There's really very little to no faulting in any of these fields in the deep woodbine that we're after. We have booked some reserves on the Hammond and Collins, and we, I think, compared to what we'll eventually have there, I won't say it's minimal but I think we have more to be able to fill in there. Collins well is not producing yet, and we are still building a pipeline waiting connection there. We'll complete that well, it's going to require -- but we won't complete it until -- we have, of course, a lot of analogies to give us some confidence on the reserves that we've booked there, and of course the Hammond well is producing in excess of 18 million a day. So we are a little early, I guess, in the evaluation of the field, but we think we've got some more to do there obviously this year.

In March, probably the end of next month, Brad, we should spud an offset well to the Collins number one well, and then we should spud an offset well to the Hammond. That's kind of our plans right now. We have budgeted to drill five wells, kind of in what we call the Ross area, which is where the Hammond and Collins wells are located. And then we'll step out from there, if you look at the well page, we'll step out from there to the south, and we've leased two to 3,000 acres and we will drill what will be -- there's the Hammond last year was the big exploration delay in that area. It will be the Robin prospect this year. And, you know, it looks as promising as the Hammond looked when we drilled it. Of course, you -- I think our technical group has worked this area since January of 1996. They've stayed in this area.

Of course the AA wellsfield has been a phenomenal success. It's produced probably370, 380 Bcfe of reserves, and we're still producing it at about 62 million a day equivalent, and we own about 40% of it and operate all of it. We have 10 or 11 to drills in kind of the heart of AA. We've spent about $150 million on it. We've gotten all of our money back and still have over110 cubic feet of gas reserves from, and from there, you keep working these fields, and the middle of 1997, all of 1998, early 1999, we participated in a 3D seismic shoot, and that's the reason that really we were able to develop AA. We took the same data to drill the Collins and to drill the Hammond wells. So again, we're still developing these fields under the same methods that we developed back in 1996.

Ok, Jay. The five offsetting to the Hammond, the Hammond area, those would be basically PUD, some reserve book and some upside maybe?

Brad, this is Mike again. We've booked two development wells off of the Collins and the Hammond, so all the locations that you'll see there in the release this morning have not been booked. Those are just locations we think would be required to develop that area if it at all ends up being productive.

Ok. Great. And kind of the same question on the Gulf of Mexico area. The 23 wells you're drilling, how many of those would be considered developmental versus exploratory?

Brad, I think -- I don't have the exact number, but I think about six to seven of those are development wells and the balance, the lion's share of those are exploratory wells because typically the typical Gulf of Mexico reservoir is a one-well field, but I think there are some development wells that are really coming along with the Shipsho 113 unit that are getting drilled. That's the difference next year. Because most years, most of the Gulf wells are definitely exploratory.

Ok, great. And Roland, do you want to give some kind of a guidance of where you think your production will be average for the first quarter? You were at 110 and you've got the south of Paltoon and plus the Hammond for the full month.

Right. We're targeting 124 kind of roughly --as an average for the first quarter. What we have, you also have the Gulf of Mexico back at full production rate where it was really the month of October in 2002 are the company's total production was down to 90 million a day. That's how much production was offline in the Gulf. So that really skewed the fourth quarter numbers. December was much better than October. So we're kind of expecting the -- between the Gulf coming back and adding the production there plus the new south Tembler production that's on line combined with the full quarter of Hammond plus half a quarter, that's really where the production increases are. And then a lot of other things that kind of offset the decline.

Ok. One other just mechanical question for you, if you don't mind. Given the low finding cost, will your DD and A rate materially change going forward? And with the change in severance tax, will your severance tax rate change?

The severance tax rate will change very small, not enough to really take into consideration what you're going to really see on severance tax is, of course, the much higher taxes because of the high gas prices will bury that savings. But there is some savings to the AA wellsfield now that we've got new certification on it as far as the type gas. But most of that impact was collecting the refunds from the past. So I think it's a very modest change there to the future lifting cost. And then finding cost, it's a factor of, you know, the different fields, you know, what share of the production they are making up dictates the finding cost. I think overall, the DD and A rate should come down, but we're not projecting that for 2003 because there are some higher cost properties that have production up like at Shipsho, their production is up now so they're kind of offsetting some of that low finding cost at the Hammond and the south Tembler area.

Thanks a lot, guys. Good job.

Thanks. Brad, one other thing. We've tried to allocate about $2 million per quarter for dry hole cost since our successful efforts. We may have more or less than that, but with the increased level of exploratory drilling and we really don't see any real -- there probably won't be a lot of impact for the change in the accounting for the seismic advances because it's kind of a break-even proposition going forward given that we wrote that off in the prior year, but really just increased level of exploratory activity. I think we're just projecting maybe 2 million a quarter versus the $1 million a quarter we were kind of predicting last year.

Ok. Great. Thanks, guys.

Thanks, Brad.

Our next question comes from Jeff Robertson from Lehman Brothers. Please state your question.

Good morning, Jay. maybe for Roland, in terms of the production outlook for 2003, are you expecting production to be fairly flat over the balance of the year after you ramp it up in the first quarter? And to get to the high side of what you all said, I think 45 to 49, if I wrote it down correctly, is that based mainly on timing of some of this drilling in southeast Texas and south Texas?

Yeah, that's right. I think we do expect to see the second quarter and the third quarter should be maybe a potentially higher level in the first with the way the timing -- the production is coming on line. But I think if it weren't - if the level stays pretty flat, then we'd be at the low end of our range. We could hit the higher end if we could see these increases in the second and third quarter.

Ok. And Mike, you talked about the pipeline for the Collins well. What kind of capacity will you have on that line, and what will be required as you drill these other five step out wells assuming you have some success there in terms of transportation out of the area?

We have a couple of ways out, and I'm not 100%up on this, but I could -

I could add, the Collins is actually being routed back up to the AA wellsfield and connected in, I think, to the wells at the south end of that field. Where the Hammond, we had a new connection -

To the east.

- to the east of the big ticket, but we've got two options to go with the gas and it depends on what's the most economic hookup.

The Hammond is relatively quick connection. To the east side, there's a pipeline. Then when we drilled the Collins, we went to the west side of the big picket then north through El Paso. You could say we're less than a month away from connecting the Collins, and Steve Neukom (ph), who is in charge of marketing our gas and oil, all the wells that we're drilling on the west side looks like it will go through this pipeline that goes to the north, connects to the AA. We have plenty of capacity there and we should have plenty of offset to the east, offset to Hammond. As far as production, remember we in August/September, we were owning a 30% interest in the south town block30, number five and number six wells, and we're spending our third of eight $8 million to put a production facility in there, so that production should come on in August or September, and between that time, we'll have the Collins come on in a month, and then we have a well at south Tim (ph), we call it the A2 well which should be producing right at 20 million a day, so we own a third of that. That should be soon in production. We call it the A3, and probably within 30 or 45 days, we should have that well connected to this south Tim facility. And we've got some wells in south Texas that we drilled last year that are waiting on pipelines. So we've got -- I think you'll see --you'll really see the results of last year start showing up this year, particularly in south Texas in some of our Gulf of Mexico successes.

And lastly, Roland, production costs, I don't know if Brad had asked this earlier, production costs, I think, were about 89 cents in the quarter, which was higher than where they've been for earlier in the year. Can you just review where that was?

Right, that was a combination of, of course, a little higher severance taxes, about $1 higher gas price in the quarter. So that was part of it. But there were also some additional costs in the Gulf of Mexico, you know, that were probably related to getting things back up and going and repairs that weren't covered by insurance. There's about $800,000 of additional field level cost in there. Part of that belonged to - just for one month belonged to the Shipsho 113property, which added part of that. But the balance is probably all the activity they had in getting things back to normal out there during the month of December, November/December.

Ok. Thank you.

On our production also, Jeff, I know you've visited with the Bodar (ph) guys a week or so ago. I don't know if they went over the 113-114 Shipsho area, but the wells we would drill there in third and fourth quarter, since the facilities are already there, we won't be waiting this year at 18 months and spending 6 to $8 million to set new facilities. We'll connect those wells to cells immediately. So I think you'll see some benefit on that in the third and fourth quarter.

Thanks, Jay.

Thanks, Jeff.

At this time, I'm showing we have no further questions.

All right. Again, it's always a pleasure to give you, you know, the facts. Sometimes they're bad, most of the time they're good. We've had a really good year, and as I said, if you followed on this web page, I mean, we really, if you look at the company's inventory of prospects, both in the shallow Gulf and on shore, we've never had a better set of properties and multi-year inventory of places to drill.

We've added, you know, strength in south Texas and we've set the stage really because we're almost at an all-time high production rate, and you look at our availability with our bank credit facility, which should be increasing, and you look at the success rate we've had and the finding costs we had last year, and the budget that we have, and particularly natural gas prices were unhedged, we really have positioned the company to have maybe the best year ever. So that's what we're going to try to produce for you. So thanks.

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