Comstock Resources Inc (CRK) 2002 Q3 法說會逐字稿

Good morning ladies and gentlemen, and welcome to the Comstock Resources third quarter financial results conference call.

At this time all participants are in a listen-only mode. Later we will conduct a question and answer session.

I would now like to turn the call over to Mr. Jay Allison, President of Comstock Resources. Mr. Allison you may begin.

Thank you.

Welcome to Comstock Resources third quarter 2002, financial and operating results conference call.

You can view a slide presentation during or after this call by going to our web site at www.comstockresources.com and clicking Presentations. There you will find a presentation entitled Third Quarter 2002 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, and Mike Taylor, our Vice President of Corporate Development, who will help answer questions.

With this call I will review our third quarter 2002 financial results as well as the results to-date in our 2002-drilling program.

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

If you're following this on page two third quarter 2002 highlights.

On the call today we're going to look at our financial results for the third quarter and first nine months of 2002. With improved oil and gas prices in the third quarter we reported a 24 percent increase in net income, with $3 million in profits from continuing operations, or 10 cents per share.

Production was up 15 percent this quarter, because of the DevX acquisition, production however decreased from our second quarter level because of disruptions and the Gulf of Mexico related to the Hurricane activity.

We continue to have excellent results in our drilling program this year but we have had 31 successes out of 35 wells drilled to date in 2002. This gives us an 89 percent over all success rate so far for the year.

The highlight of this year is the successful number one well, we were not able to get the number one connected to sales in the third quarter. However we put it on sales last week and it has performed very well, it is currently flowing at 18.6 million cubic feet a day equivalent with over 9 thousand pounds of flowing tubing pressure on a 21 64 fence choke.

Revenues, page three. Our third quarter revenues increased by 21 percent over last year to $35.7 million from $29.4 million. For the first nine months of this year our revenues totaled $100.4 million a decrease of 30 percent of a revenues in the first nine months of last year a $142.6 million.

Page four. EBIT X. Earnings before interest taxes depreciation amortization and expiration expense or EBIT X increased 11 percent in the third quarter to $24 million is compared to $21.7 million in the third quarter of 2001. EBIT X in the first nine months of this year totaled $70.4 million down 39 percent from EBIT X in the first nine months of 2001 of $115.5 million.

Page five. Cash Flow. Operating cash flow. Our cash flow from operations decreased five percent in the third quarter of this year to 16.2 million from $16.9 million in the third quarter of 2001. The decrease is due to the payment of $3 million in third quarter to settle derivative contracts with acquired in the DevX acquisition last year.

The loss of the contracts was taken in the first and second quarters of this year but the cash impact was felt this quarter. Operating cash flow for the first nine months of this year was $48.5 million down 50 percent from cash flow of $97.1 million for the same period of last year.

On a first year basis, our cash flow from operations decreased in the third quarter to 48 cents from 50 cents and the third quarter of 2001. For the first nine months of this year, our cash flow per share came in at $1.43 down 49 percent from last year's cash flow per share for the same period of $2 and 79 cents.

Page six. Earnings. We reported a net profit from continuing operations with $3 million for the third quarter as compared to $2.4 million in the third quarter of 2001. The third quarter result were 24 percent higher in 2001's third quarter. For the first nine months of this year we had net profits from continuing operations of $1.5 million as compared to $38 million in income for the first nine months of 2001.

We had 10 cents in earnings per share in the third quarter as compared to 8 cents and 2001's third quarter. We made 5 cents per share in the first nine months of this year as compared to earnings per share of $1.13 in the same period in 2001.

We also had a $1.1 million loss with 4 cents per share from discontinued operations which represent the sale of certain marginal South Texas properties we sold in the first and second quarters of this year.

Page seven. Production. Production in the third quarter averaged 108 million cubic feet equivalent per day which represents a 15 percent increase from 2001s third quarter. We averaged 32 million a day equivalent in East Texas North Louisiana.

28 million cubic feet per day equivalent in SouthEast Texas. 32 million cubic feet equivalent per day in our Gulf of Mexico region and 16 million cubic feet equivalent per day in South Texas and other regions during the third quarter.

Production decreased seven million per day in our Gulf of Mexico regions in the third quarter from the second quarter due to disruptions from the hurricanes. Our production in the Gulf continued to be hampered in the fourth quarter by the hurricanes as we were shut in for part of October and our sale one property remains off line for all of October and part of November waiting repairs to a production barge that was damaged by the storms.

We expect to show an increase in production in our SouthEast Texas region in the fourth quarter now that the number one well is on line. Page eight. Average oil prices. Our average oil price realizations improved modestly in the third quarter.

Our average oil prices increased four percent from $26 and 29 cents in 2001s third quarter to $27 and 30 cents in the third quarter 2002. For the first nine months of this year our average oil price has decreased 11 percent to $24 and 16 cents as compared to $27 and 19 cents in 2001.

Page nine. Average gas price. Gas prices were up slightly in the third quarter as compared to last years third quarter but still are significantly below last year for the nine-month period. Our average realize gas price in the third quarter was $3 and 31 cents nine percent higher than our third quarter 2001 average price of $3 and 03 cents.

For the first nine months of this year our gas price averaged $3 and 06 cents 42 percent lower than our average price of $5 and 25 cents in the first nine months of last year.

Page 10. Costs per MCFE. Costs per unit of production in the third quarter our lifting costs per MCFE produced decreased by three cents to 79 cents from 82 cents in 2001. Our GNA expense per MCFE increased to nine cents in the third quarter from seven cents in 2001 due to increases in personal costs in 2002.

DDNA per MCFE produces decreased by 11 cents in the third quarter to a dollar 26 from a dollar 37 in the third quarter of 2001. Page 11. Costs per MCFE. Our lifting costs per MCFE produced decreased by nine cents for the nine months ended September 30th from 88 cents in 2001 to 79 cents due to lower production taxes resulting from the lower oil and natural gas prices that we had for this period.

Our GNA expense per MCFE increased to nine cents from the first nine months of this year from seven cents in 2001. DDNA per MCFE produced has increased by two cents in the first nine months of 2002, to $1.28 compared to $1.26 for the same period in 2001.

Page 12, cash margins.

Due to higher prices in the third quarter and the improvement in our per unit cost, our cash margin per unit of production increased 14 cents in the third quarter to $2.65 per as compared to $2.51 in 2001's third quarter.

As a result of much lower natural gas prices, our cash margin for the first nine months of this year fell to $2.35 per from $4.12 per for the same period last year.

Page 13, capital expenditures.

In the first nine months of this year we spent $57.7 million on capital expenditures in connection with our drilling program. We spent $16 million to drill 21 development wells, all of which were successful. We spent an additional $9.8 million on work overs, recompilations, and production facilities.

We spent $30 million on our exploration program, which is over half of our total expenditures. $22.8 million was spent to drill 14 exploratory wells, 10 were successful and four were dry holes. $9.1 million was spent for acquiring exploratory acreage, seismic data, and for other costs.

Page 14, capitalization, our balance sheet.

At the end of the third quarter we had $372 million in total debt. We were able to reduce our debt by $12 million during the quarter. We had $152 million outstanding under our bank facility, which has a $250 million barring base. We have over $98 million available under our credit facility.

We ended up with $218 million in book equity at the end of the quarter. Our debt to equity fell to 63 percent at the end of the quarter.

Now to go over our major producing regions.

Starting with East Texas, North Louisiana which is page 15. Our results from East Texas, North Louisiana regional area.

In the first nine months of this year we spent $14.6 million drilling 17 wells net wells, 16 of which were successful with one exploratory dry hole drilled in North Louisiana. Fifteen of these wells were in the that we acquired in the DevX acquisition.

We have been able to test 12 of these wells at a per well average rate of 1.5 million cubic feet of natural gas equivalent per day. We plan to drill two more wells in this region in North Louisiana in the last quarter of this year.

Page 16, our Gulf of Mexico region, the results.

Our Gulf of Mexico drilling program has been successful to-date this year. Since the beginning of the year Comstock has drilled nine wells in the Gulf. We spent a total of $30.4 million, including 4.8 million on acquiring leases and seismic data, and $3.6 million on production platforms.

Seven of the nine wells we drilled were successful. The remaining two wells were which were drilled at and . Six of the seven successful wells have been completed, and were tested at an average per well rate of 6.7 million cubic feet equivalent per day. The remaining well is in the process of being completed, and in the third quarter we made one significant discovery in the Gulf, the state leaves 16 5 28 number one is self-built of block 11. The south 11 well was drilled to a depth of 13,933 ft and found approximately 123 feet of net pay in five separate reservoirs.

This well in south block 11 well was tested at 740 barrels of oil per day and 3.8 cu. ft. equivalent to gas per day. We have a 33 percent working interest in this discovery well. We are currently drilling in a exploratory well at south block 30 and plan to drill two more exploratory wells in the Gulf by the end of the year.

The South Texas region, page 17, we spent $9.6 million in our South Texas exploration program this year, we have experienced some very encouraging results, so far this year, we have drilled six exploratory wells, five of the six wells were successful. Three of the successful wells drilled on the Bar Ranch Prospect in Kennedy County, Texas, two of these wells were tested at an average per well initial production rate of 7.8 million cu. ft. equivalent per day. We have a 20 percent working interest in these wells.

The stock in number one well was drilled to test the charcoal prospective in County, Texas, we expect that well to be producing at around 8 to 10 million per day after a is completed. We have a 17 percent working interest in that discovery. We also made a discovery in the number one well, which tested our prospective in County. We found about 25 feet of net pay in the well and we are in the process of testing the well currently.

We operate and have a 45 percent interest in the number one well. The one dry hole that was drilled was at Patterson Ranch. We plan to drill four additional exploratory wells in South Texas by the end of the year.

Our South East Texas region, the double A area, page 18, we spent $3.1 million drilling the successful hammer one explanatory prospect, approximately 1.5 miles south of the WA Wellsfield. The Hammer number one well was directionally drilled to total depth of 15788 ft. and was completed in the upper woodbine formation. We own a 58 percent working interest and operate the well. After installing a pipeline in the required surface production equipment, the well was taken to sales at 18.6 million cu. ft. equivalent per day with over 9,000 pounds of flowing tapering pressure on a 21 64 bench choke.

We plan to drill two more wells as offsets to the Hammer number one in order to further define the Eastern and Western development of this discovery. Both of these planned wells will be drilled to a total depth of 15,000 ft, we are currently drilling the field number two well, the Eastern offset well to the Hammer number one which is at approximately 14,100 ft. a day where we are setting 7 and 5 inch intermediate casing. We will spud the Collins of number one well, as the Western offset well to the Hammer number one before the end of the year. The field number two well in the Collins number one well are vertical wells, unlike the number one which had to be drilled directionally. Page 19. The outlook for 2002.

Our target for production this year is 41 to 42 BCFE after accounting for loss production due the hurricane activity in the Gulf. We still plan on spending approximately $75 million on our drilling program this year. We've drilled 35 wells so far this year with 31 successes for a success rate of 89 percent.

The number one discovery will give us a production boost in our SouthEast Texas region as well as add significant reserves by the end of this year. We have substantial up side with our multi year inventory of billing prospects up in the Gulf of Mexico and in South Texas.

And lastly we have substantial financial flexibility to continue to implement our business plan. Our drilling program has been funded out of operating cash flow and we managed to pay down $12 million in debt this last quarter.

We also have $98 million available on our revolving credit facility to provide additional equity if needed. With that let me turn it over for questions please.

Thank you. We will now begin the question and answer session. If you have a question you will need to press the one on your touch tone phone. You'll hear an acknowledgement that you have been placed in queue.

If your question has been answered and you wish to be removed from the queue please press the pound sign. Your questions will be queued in the order that there are received.

If you are using a speakerphone please pick up the handset before pressing the numbers. Once again if there are any questions please press the one on your touch tone phone. We have Wayne Anders from Raymond James on line with a question. Please state your question.

Hello Jay, Roland. Good job on the quarter. Just had a quick question on the well which sounds like an awesome well. Can you compare that to the better wells and the double A wells field and how is that as far as IP rates and cumulative production on some of those other wells?

Yeah Wayne this is Mike Taylor I can answer that.

Hi Mike.

The better wells and double A wells specifically the Carter number six, Carter number seven about 10 years ago, eight to 10 years ago those wells were drilled. They came in at 15 to 16 million a day. They had little more than this well does.

They produced a thousand or two thousand barrels of per day at about seven to eight thousand PSI and this was before full development of the field but those wells have produced 20, 25 BCFs still flowing two to three million a day and they have more section but the porosity was perhaps not quite as good as what we've seen down in area.

There are some similarities there so differences. We think that we may have area of better thickness away from the well but the well is, is a I think every bit as good as those wells.

Very good I think that answers my only question but excellent job on the quarter and keep up the good work. Thank you.

Thanks Wayne.

Thank you.

We have from Friedman Billings Ramsey on line. Please go ahead.

Good morning Jay. Real quick question on exit rates. Do you want to take a stab at it after you bring your Gulf of Mexico I mean on production on line continues to produce. What other should we thinking about as an exit rate for 2002?

I think going on where we are today, we've tried to assess where we are even though we have production off itself land from New Field's wells it should fill 69 because of Hurricane Lilly.

I think our production today we're approximately right now at about 115 million cubic feet equivalent per day.

OK.

We probably have another four million a day that still a shut in because of the Hurricane. About two million from the South Helter Wells because of the . A couple of million from New Fields Wells the ship showed 69 so with those you know we'll be about 119 or so a day.

We have four wells right now, which are actually we're completing and recompleting. Three are on shore, one is off shore and you can safety say that that'll add another five million a day. So that puts us in the 120 to 124 top range.

Now I think if you look at what we're doing right now is to drill bit or will do by the end of the year. We'll get three wells if we're drilling on shore currently which is the Vast RP number two which is the Eastern offset to the number one.

Right.

And we should see these out wells right on and I'd say two weeks because we're setting in our media right now.

OK.

Then we're drilling a well in East Texas, the eight of field and then we're drilling another well called the Soother Baker Well. So we've got three wells that we're drilling on shore, which will be you know hooked up to cells by January and then we've got five or six wells on shore that we will, we plan to drill between now and year end which will take us over into January.

And then off shore, we're currently drilling A Well and we're re-entering a well, so two wells there. And then we've got two more wells by year end and we'll drill so we've got roughly five wells that are busy now and then in addition to that we've got seven to eight wells that we will be drilling between now and into mid January.

But if you look at our current net production that we think we'll get back on from the South Well on wells and the production we're currently completing these wells, we should be in the you know a minimum of 120 to 125 plus. You've got the five wells for drilling plus the seven to eight that we will be drilling.

So a lot of more momentum going into the new year, that sounds pretty good. A couple of more quick little details questions here. In terms of reserves number one well and also the are off fee, what are you guys thinking about this all the extension of the field?

Well what we're done in you know we've been cautious on giving out any reserve numbers because what we want to do is we, you know we've looked at the original WA wells field and you know the reserves are you know maybe well their you know maybe 200 BCF feet, who knows what the reserves are in those major fields.

But what we've done with the number one we said a couple of years ago, we identified the prospect as the Ross prospects if you remember.

Right.

We took the Ross prospect. We found pay in it we completed it and that really set up the number one well, so we went a little north, north west and we drilled the well and that was in July.

We completed it, we started producing it probably seven days ago at this 17 - 19 million a day equivalent and then what we said you know as a Board of Management, we said well, number one do we have the acreage leased based upon the 3D so we've covered most of the acreage where we think the reserves are? And the answer to that is yes.

And then we said how about lease acreage exploration issues. And that's why we went to the East to drill the number two well first. That is not our primary choice for a second well. We would go West.

But we had an acreage exploration issue to the East and so we said OK we will drill that well. If it is a great well then that's good, but if it's a marginal well then we still wouldn't choose that location for our second - we go west.

But we - you know, it is an exploratory well. We think it'll be a good well, we'll know in a couple of weeks. But we want to drill that, we want to complete that well if appropriate. And then we want to this number one well to the west.

And we've had 21 inches of rain in in the last month.

OK.

And to - in order to build that location it right now would cost us a couple of hundred thousand extra dollars to build the location. It's just a mud pit out there.

Got you.

In fact is out there today, out there, is out there, Head of Operations for . They're all out there right now with .

But what our goal is is in the next month, you know, try to build a location, start the well let's say by the middle of December. That's kind of an arbitrary goal, if we can do it faster we'd do it. But let's say within the next month have the location built.

And then we would have that well down probably by the latter part of January. And by that time we'd really be able to assess what type of reserves. It - if it proves up to be what the shows, then you know, as a management group we'd try to come in and say what kind of capex budget will we have for 2003?

Right.

Where do you allocate your money?

Right.

And looking at we'd say well if we can prices at $4, our gas prices at $4, then if there's another eight locations that we should drill then we should go ahead and drill them. And we'll allocate $10 or $15 million in that area to drill wells.

But I don't think we can, you know, we can throw out any numbers. They would be pretty big numbers for reserves, based upon the type well that we think we have here. I mean I think it's a real deal.

You look at where it's located, how long it took us to develop. You look at the , you look at the bottom hole pressures. You look at the pressures. Really this well could produce a lot more if we had different in it.

So I don't know. It's one of those events that happen in really good areas that you just have to keep working at. And they happen sooner or later, and I think we've gotten one of them.

So let me see if I've got the time-line down correct.

First of all reserve size, it's a little bit too early to talk about it, maybe end of January by the time you're done with number one is when you can really come back and say what you really have. And then that will be reflected by how much capital spending you talk about in the area come early January.

Would that be fair to state that?

Yeah I think that's right.

OK.

And also if the second one - second extension to the East doesn't work out, we shouldn't be concerned because that's not what we really are chasing? If it comes in fine. Otherwise the potential that's there really heads West?

That's correct. And Mike, do you have any comments on that?

Well I think that that's a pretty good assessment. We have - the fields will not be fully assessed by these two wells . It would be an ongoing development. We would be able to test some of the - we test the Eastern limit I think with this field number two that we are drilling now, we would step out not totally to the western edge with the Collins well so we will have a couple more data points but we'll certainly have a better handle on it at that point, but I wouldn't say that we would have the field evaluated with two wells, I think it is going to take some time to do that.

Right, I totally agree, the other thing, you ask about an exit right, if you remember when we bought DevX, the only value we gave to South Texas was the dollars that they spent for size and lease hold, the problems that they were in, and one of the big surprises were the DevX acquisition is the success that we have had in South Texas, we've drilled a charcoal well, several ball ranch wells, you know, we will be drilling a low pares opinion and we drill the well itself from to we probably have another easy $15 million of expiration wells and developmental wells easy, in South Texas for 2003, and so that is something that entering 2002, we didn't know that we would have, but we've had really good success and we've been able really to become the operator by acquiring more interest in some of these wells and that's been even better.

Sticking to the bud of the capital spending here, you talk about 15 to 20 million in South Texas, similar kind of program to 2002 I would presume, South East Texas another 50 to 20 million, do you want to take a stand by at what your Gulf of Mexico might look and then basic the total capital spending program?

We haven't really published one yet, you know the number that we are throwing around internally is maybe $100 million and we will allocate that out, hopefully half of it or more would be on shore and it seems like half of it or maybe 55 percent of it is in the Gulf, we've got some great exploration prospects in the Gulf and I think all of them in 2003 would be near existing production facility, so hopefully we wont be tying up, four, five, six, $7 million on wells that we have drilled and have to wait to sit production facilities. At least that is our internal thinking right now.

OK one last question. Finding cost for the year are reserve placement rather than any estimates what you guys are hoping for.

No we are still, I mean, we are still drilling too many high impact wells to have it yes right now.

OK thank you guys.

Thanks .

Once again, if there are any questions, please press the one on your touch-tone phone.

Gentlemen we have no further questions at this time. Do you have any concluding remarks?

No I would just like to thank you for listening in, I know some other companies had conference calls and you chose to listen to this one and I think that is the right choice obviously, and you know, we are thankful for that, so, that's all. Thank you.

Thank you for participating in today's teleconference. You may now disconnect at this time.