Comstock Resources Inc (CRK) 2002 Q2 法說會逐字稿

Good morning, ladies and gentlemen. And welcome to the Comstock Resources second 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. Mr. Allison, you may begin.

Thank you. Good morning, everyone. Welcome to Comstock Resources's second quarter 2002 financial and operating results conference call. You can view a slide presentation during our or after this call by going to our website at www.comstock resources.com and clicking "presentations." There you will find a presentation entitled, "Second Quarter 2002 Results." To change the page in the presentation, click on the arrow on the page.

I'm Jay Allison, President of Comstock. 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 today.

With this call, I will review our second quarter 2002 and six months into June 30, 2002 financial results, as well as results to date of our 2002 drilling program. Our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations and such statements to be reasonable, there can be no assurance that such expectations will prove to be correct.

Page 2: Second Quarter 2002 Highlights. On the call today, we're going to look at our financial results for the second quarter and the first half of 2002 which were much lower than the comparable results in 2001. Lower revenues, cash flows and earnings this year are the result of lower oil and natural gas prices. With improved oil and gas prices in the second quarter, we returned to profitability, posting a $3.2 million profit from continuing operations, or is 11 cents per share.

Production was up 12 percent this quarter because of the Devex acquisition. We continue to have excellent results in our drilling program this year where we have had 24 successes out of 27 wells drilled to date so far in 2002.

The most significant development, as you may know, since our last conference call is the success of the Hammond well in Polk County. If results hold up, we could have a material increase in our proved reserves because of this discovery.

Page 3: Revenues. Our second quarter revenues of $38 million were down 17 percent as compared to last year's second quarter revenues of $46.1 million. For the first half of this year, our revenues totaled $67.4 million, a decrease of 43 percent over revenues in the first half of last year of $113.2 million.

Page 4: EBITDAX. Earnings before interest, taxes, depreciation, amortization, and expiration expense or, EBITDAX, decreased 23 percent in the second quarter to $28.5 million as compared to $36.9 million in the second quarter of 2001. EBITDAX in the first half of this year totaled $46.4 million, down 51 percent from EBITDAX in the first half of 2001 of $93.8 million.

Page 5: Cash Flow -- Operating Cash Flow. Our cash flow from operations decreased 32 percent in the second quarter of this year to $21.1 million from $31 million in the second quarter of 2001. Operating cash flow for the first half of this year was $32.4 million, down 60 percent from cash flow of $80.2 million for the same period last year.

On a per share basis, cash flow from operations decreased 30 percent in the second quarter to 62 cents from 89 cents in the second quarter of 2001. For the first six months of this year, our cash flow per share came in at 96 cents, down 58 percent from last year's cash flow per share for the same period of $2.29.

Page 6: Earnings. We reported a net profit from continuing operations of $3.2 million for the second quarter as compared to earnings of $12.3 million in the second quarter of 2001. For the first half of this year, we had a $1.5 million loss as compared to a $35.7 million gain in the first half of 2001.

We had 11 cents in earnings per share in the second quarter as compared to 36 cents in 2001's second quarter. We lost 5 cents per share in the first half of this year as compared to earnings per share of $1.04 for the same period in 2001.

In the quarter, we had a $403,000 loss from discontinued operations which represented the sale of our El Campo field. For the six months ended June 30, 2002, we had a $1.1 million loss from discontinued operations which represented the sale of our El Campo field and the marginal south Texas properties we sold in the first quarter.

Page 7: Production. Production in the second quarter averaged 116 million cubic feet equivalent per day, which represents a 12 percent increase from 2001's second quarter and a three percent increase from the first quarter. We averaged 35 million cubic feet equivalent per day in our East Texas/North Louisiana region, 27 million cubic feet equivalent per day in our Southeast Texas region, 39 cubic feet equivalent region in our Gulf of Mexico region, and 15 million cubic feet equivalent per day in South Texas and other regions during the quarter.

Production increased 17 percent in our Gulf of Mexico region with the hookup of several new wells earlier in the quarter. With the success of the Hammond discovery in Polk County, we expect production to show an increase in the Southeast Texas region starting in the third quarter when this high-volume well is put online.

Page 8: Average Oil Prices. Our average oil price realizations were down in 2002 as compared to last year. Oil prices decreased 7 percent from $26.97 in 2001 second quarter to $24.59 in the second quarter of 2002. For the first six months of this year, our average oil prices decreased 17 percent to $22.79 as compared to $27.60 in 2001.

Page 9: Average Gas Price. Gas prices have decreased significantly in 2001 over last year. Our average realized the gas price in the second quarter was $3.47, 31 percent lower than our second quarter 2001 average price of $5.03. For the first half of this year, our gas price averaged $2.93, 53 percent lower than our average price of $6.28 in the first half of last year.

Page 10: Cost per Unit of Production. Our lifting cost per MCFE produced decreased by 7 cents in the second quarter to 80 cents from 87 cents in 2001. The increase is due to lower production taxes related to the lower oil and gas prices. Our G&A expense for MCFE decreased to 10 cents in the second quarter from 11 cents in 2001. Depreciation, depletion, and amortization for MCFE produced has increased by 6 cents in the second quarter to $1.30 from 1.24 in the second quarter of 2001.

Page 11: Cost per MCFE. Lifting cost per MCFE produced decreased by 11 cents for the six months ended June 30th from 91 cents in 2001 to 80 cents due to the lower oil and gas prices. Our G&A expense for MCFE increased to 10 cents in the first half of this year from 9 cents in 2001. Depreciation, depletion, and amortization for MCFE produced has increased by 9 cents in the first half of 2002 to $1.29 from $1.20 in the same period in 2001.

Page 12: Cash Margin. Due to lower oil and gas prices, our cash margin of unit per production decreased 31 percent in the second quarter to $2.70 per MCFE as compared to $3.92 in 2001's second quarter. Our cash margin decreased 55 percent in the first half of this year to $2.21 per MCFE from the cash margin of $4.86 per MCFE for the same period last year.

Capital Expenditures: page 13. In the first half of this year, we spent $37.5 million on our drilling program. We spent $11.5 million to drill 16 development wells, all of which were successful. We spent an additional $2.8 million for workovers and recompletions, and $2.3 million on offshore production facilities.

We spent $20.9 million on our exploration program, which was over 1/2 our total expenditures. $15.5 million was spent on drilling 11 exploratory wells, eight of which were successful, and three were dry holes. $5.4 million was spent on exploratory acreage and seismic data, and we have spent half of our $75 million drilling budget so far this year.

Capitalization: page 14. Our balance sheet. At the end of the first quarter, we had $384 million in total debt. We had $$164 million outstanding under our new bank credit facility, which has a $250 million borrowing base. We have $86 million available under the credit facility. And we ended up with $215 million in book equity at the end of the quarter. Debt as a percent of our book capitalization is 64 percent as of June 30th of 2002.

Now I'd like to review the performance in our main regions, which are East Texas, North Louisiana region, our Gulf of Mexico region, our South Texas exploration program, and then our Southeast Texas region. We'll start with our East Texas/North Louisiana regional results, which is page 15.

In the first half of this year, we spent $10.1 million drilling 13 wells, or 4.9 net wells, all of which were successful. All of these wells were drilled in the Gilmore field that we acquired in the Devex acquisition. Ten of these wells have been tested at a per well average rate of 1.5 million cubic feet of natural gas equivalent per day. An additional 5 wells are planned at Gilmore for the remainder of the year. And we also plan to drill 3 more wells in North Louisiana in the last half of this year and this region.

Our Gulf of Mexico region: page 16. Our Gulf of Mexico drilling program has been successful to date this year. Since the beginning of the year, Comstock has drilled 7 wells, or 2.7 net wells, in the Gulf. We spent a total of $20.6 million, including 2.6 million on acquiring leases and seismic data, and $2.3 million on production platforms. Five of the seven wells we drilled were successful. The remaining two wells were dry holes which were drilled at South Timbalier Block 30, the number 4 well, and at South Pelto Block 1.

Four of the five successful wells have been completed and were tested at an average rate at 7.8 million cubic feet equivalent per day per well. The remaining well is in the process of being completed.

In the second quarter, we made two discoveries in the Gulf: the state lease 17309 number one, and Ship Shoal Block 67, and the OCSG 13928 number 6, at South Timbalier Block 30 the number 6 well.

The Ship Shoal 67 well was drilled to a depth of 13,826 feet and found pay in three separate sands. The lower-most sand was tested at 4 million cubic feet equivalent per day, and we have a 50 percent working interest in the well.

The South Timbalier 30 well was drilled to a depth of 14,600 feet and found approximately 40 feet of net pay in two separate reservoirs. Completion of this well will take place as our production facilities are installed. We have a 34.4 percent working interest in this discovery. We are currently drilling an exploratory well at South Timbalier Block 11, which looks promising, and plan to drill four more exploratory wells in the Gulf by the end of this year.

Page 17: Our South Texas Exploration Program. We spent $3.6 million in our South Texas expiration program this year. We have experienced some early encouraging results so far this year. In the second quarter, Comstock has drilled four exploratory wells, three of the four wells were successful. Two of the successful wells were drilled on the Ball Ranch prospect in Kennedy County, Texas. These wells were tested as an average per-well initial production rate of 7.8 million cubic feet equivalent per day. We have a 20 percent working interest in these wells.

The other successful well was drilled to test the Charco prospect in Goliad county County, Texas. The Stockton #1 was drilled to a relative depth of 15,540 feet and completed as a new field discovery. Wireline logs indicate that approximately 190 feet of potential productive gas pay is present in four lenticular sand packages. We have a 17 percent working interest in this discovery. 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 this year.

Page 18: Our Southeast Texas Region. We spent $1.5 million drilling an exploratory prospect 1 1/2 miles of the Double A Wells field. The result was a major new discovery well with the Hammond #1. This well was directionally drilled to a total measured depth of 15,788 feet, and its natural completion was tested at a rate of 13.5 million cubic feet of natural gas per day and 100 barrels of condensate per day.

We expect that this well can produce at a daily rate of 15 to 12 million cubic feet of natural gas per day, and we plan to have the well connected to sales by the latter part of this month. We own a 58 percent working interest and operate this discovery well. We plan to drill 2 more wells this year to delineate the reserves discovered with this successful well.

The outlook for the remainder of 2002. With the Devex acquisition, our target for production this year is 44 BCFE for an increase of 16 percent over 2001's production. We plan to spend $75 million to drill roughly 49 wells this year. We have drilled 27 wells so far this year, with 24 of the 27 being successful for a success rate of 89 percent.

The Hammond discovery in Polk County will give us a production boost in our Southeast Texas region, as well as add significant reserves by the end of the year. We have substantial up-side in our multi-year inventory of drilling prospects in the Gulf of Mexico and in our south Texas region. And lastly, we have substantial financial flexibility in place this year to weather low gas prices.

Our drilling program will be funded out of operating cash flow, which has been shored up by our decision to hedge approximately half of our natural gas production at $3.46 through October to ensure that we can cover our drilling expenditures. We have also have $86 million available on our new revolving credit facility to provide additional liquidity,if needed. With that, I would like to open it up to questions.

Thank you. We will now begin the question-and-answer session. If you have a question, you will need to push the 1 on your touch-tone phone. You will hear an acknowledgement that you have been 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 they are received. If you are using a speaker phone, 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 Wayne Andrews from Raymond James. Please state your question.

Hello, Jay, Roland, Mike. I just had a quick question regarding the Hammond well and how that completion compares to the original wells in the Double A Wells Field in the interior. You mentioned 13.5 million a day natural. How does that compare to the original discovery wells in the heart of the field? And I have a follow-up, as well.

Okay. Wayne, this is Mike. The original wells that of course were drilled in '85 were off on the flag, but what you're referring to are the wells that Carter 6, Carter 7 that are in the heart of the channel that Flagstone drilled in '92. And those wells exhibited IPs in the 15 to 20 million a day area and maintained that production for quite some time. Those wells will go on to [accumulate] between 20 and 40 BCFE each, of course those are the best wells in the field. And what we see as far as initial rates looks similar. We don't have quite as much sand thickness here as we had in the main part of the channel, but we have some more development to do. So we're pretty excited about it.

Sounds like a great well. Also, maybe you can comment just on the possibility of additional infill wells on the reservation, maybe how that's proceeding.

We have plans, of course, to drill some more wells with the resolution of dispute with the Alabama (indiscernible) tribe coming to an end, we think, in the next few months. So we have a number of wells we would like to do to finish the development there in the field.

Great. Thanks very much. Good quarter.

Thank you. My only comment, Wayne, would be that, you know, we're proceeding with the settlement with the [Cashatas] on a friendly basis, and I think we should hopefully be there, as Mike said, in the next 30 to 60 days. We have agreed to settle.

And the second comment I guess on the Hammond would be that we do have 18 to 20 percent porosity in the Hammond well, which was, you know, as good or might be a lot better than the other wells that we drilled in the region. And what our goal is, is, you know, maybe to drill the two more wells this year and maybe drill a total of maybe 6 or 7 wells, and that's a guesstimate right now.

But what we would like to do is that number of wells to prove out maybe a couple of hundred BCFE of reserves. And we think that's possible and we'll proceed, you know, in a very orderly manner to do that and produce the wells and see what the reservoir size is, because that's the only issue that remains out there.

Very good. And the 15 to 20 million that you said might be an initial production rate, is that after a stimulation or would you expect to produce that natural as it is today?

We think that has the capability of doing that naturally. The initial test, of course, the test periods are somewhat limited, but we had good indication, as Jay mentioned, of high porosity, high permeability, which could be a little bit better than what we saw in the field. And we go on to track all these wells because of the varying permeability throughout the reservoir, but initially we most likely will not crack the well.

Very good, thank you.

Yes, sir.

We have Jim Sterling from American Energy Fund. Please state your question.

Yes. Wonderful results. Hopefully the stock will reflect the potential. Could you give me on the more significant wells that you mentioned, their open flow rates, could you give me the choke sizes and what -- if you happen to have them handy -- and what your flowing tube pressure was. And thirdly, on the Hammond well, what the decline rate might be off of that 15 to 20 million a day. And I'm sure it won't stay there the whole year.

Hang on a second, Jim.

We've got that test result here. [ Pause ]

Jim, I don't know if we have all that in front of us.

If you don't, don't worry. I'll follow up separately.

Okay.

At a later date.

I don't have the choke sizes and tubing pressures. I can tell you that the flow rate -- the flow pressure did not draw down significantly during the test. The choke sizes were restrictive because of the -- really, the transportation rate of the tubing, the diameter of the tube something not large enough to transport all that the well would produce.

This is the Hammond?

Yes, on the Hammond.

Right. It was 1664 an inch choke on that test.

So on a quarter inch choke, we had -- (indiscernible).

That was in the press release, Jim. That's where we're pulling that out of.

Quarter inch choke, at 10,300 pounds flowing tubing pressure. So it was very high flow rate. Very high pressures. As far as decline rates, it's -- that's going to be, of course, dependent on the size of the reservoir, and we have more work to do there as far as development to do before we can really determine what kind of decline rates we'll have. We would have to have an idea of what the end point is. But if it's similar to our target of 100 to 200 BCF field, it's just going to depend on how many wells we have in the field, of course. So I would point out again, though, that the big wells in Double A Wells have held up that rate for a period of years before declining and subsequent development.

We own in -- I don't know if I'd comment -- we own in that Hammond area, we own a 58 percent working interest. So not all that production will be ours. But at least over half of it will be. And we do operate that field.

Your other wells were all on chokes of varying sizes, the other open flow figures that you gave.

Yeah, I'm sure that's correct.

Yes, sir, that's right. We can give you more detail if you want to call in after the conference call.

This was not an AOF that you would file with the railroad commission. This was an actual measured flow rate. So we want to make that point.

Thank you very much.

Yes, sir.

Thank you, Jim. If you need again more information, give Mike Taylor a call on that.

Once again, if there are any questions, please press the 1 on your touch-tone phone. We have Gary Stromberg from Bear Stearns online with a question. Please state your question.

Good morning. Can you update us on your hedging program on the natural gas side for this year, and if you've added anything for 2003?

Sure, Gary. This is Roland. What we did, then -- we should have highlighted it in our discussion -- is we settled the Enron positions that we inherited through the Devex acquisition this quarter. And so those are pretty much eliminated, and we agreed to a settlement pretty much the amount that we marked those contracts to market at the end of the first quarter is kind of where we settled them out at, so there wasn't a lot of additional impact.

So those hedges are now -- those positions which were at $2.40 gas price are gone now and don't continue, you know, into the third quarter. And we still have about half of our gas production hedged through all of the third quarter and just through the month of October at the $3.46 cents. And that's really the only significant position that we have.

Do you see adding any hedges into '03?

Yeah, that's possible. We are looking at, uhm, looking at similar strategy that we had for '02 was when we looked at our total capital drilling budget, we might employ a similar strategy to hedge a portion of the gas to ensure that we can fund all of the drilling budget through cash flow.

Okay. Thank you.

All right.

Gary, we have no hedges, as you know in 2003, as Roland stated, and we are looking maybe to have the same strategy next year that we had this year.

Once again , if there are any questions please press the 1 on your touch-tone phone. At this time, we have no further questions.

All right. I guess in closing I would just like to state that what we try to do as a company is we try to stay well balanced both on shore and offshore. 70% of our reserves are on-shore, 30 percent of our reserves are off-shore. About 2/3 of our production is on-shore a third of it is off-shore. So I think that is well balanced. Again, we plan on funding our drilling program between now and year end through free cash flow.

And as far as growth in the company, I mean, what does tomorrow look like? If you look at our core areas in the Gulf of Mexico, again, we have 38 prospects and counting with about a trillion cubic feet equivalent of unrisked reserves, and in most of those prospects we own anywhere from 33 to 40 percent. So we probably have 400 BCFE of reserves net to our interest.

And then if you look at the Hammond area in Polk County which is south East Texas, it's been a wonderful field for us since 1996 when we first acquired interest and became operator, I think we drilled some 40 wells in that area since we first owned it. And, of course, the initial purchase price of $104 million has paid itself off, and we still over 100 BCFE reserves in the area. And maybe we can extend that with this new discovery, the Hammond #1; that's our goal. We'll be working on that this year.

I guess that Hammond well is our best expiration discovery on-shore in the history of the company, so I don't want to exaggerate the impact, but it is definitely a very important well in a core area that we've made a lot of money in. And the reserve potential, you know, net to Comstock may be 100 BCFE. We'll work on that.

And then I think the final area, which is a new area, which is kind of a prized part of the Devex acquisition, is the South Texas exploration program. We didn't give any value to program when we bought Devex as far as what we paid per MCFE of reserves. And as we stated today, we have drilled, I guess, four or five wells in the area. We've had one dry hole, which was at Patterson. We have had three successful wells at Ball Ranch and one at Charco, which is the Stockton well, and they all have looked very promising. We think we have anywhere from 160 to 200 BCFE of net reserves for up-side there which are unrisked and exploration program.

So we're excited about where we are as a company, and we'll continue to grow it. So thanks for your time.

Thank you. Ladies and gentlemen, this does conclude our conference for today. Thank you for participating. You may now disconnect.