Coterra Energy Inc (CTRA) 2002 Q3 法說會逐字稿

Good day, everyone and welcome to the Cabot Oil and Gas corporation quarterly results conference call. Today's conference is being recorded. Today's presentation will be available for replay at 12:30 Eastern through November 1st at midnight. You can access the replay by dialing 719-457-0820 or toll free 888-203-1112 and entering the passcode 488719. Again, those numbers, 719-457-0820 or 888-203-1112 and passcode 488719. At this time, for opening remarks and introductions, I turn the call over to the Chairman and Chief Executive Officer, Mr. Dan Dinges. Go ahead, sir.

Thank you, Clay. Good morning. Thanks for joining us today during this third quarter earnings teleconference call. I'm Dan Dinges, Chairman, President, CEO of Cabot Oil and Gas. With me today we have several members of our management team. Mr. Michael Walen, Senior Vice president. Scott Schroeder, our CFO. Jeff Hutton, our VP of Marketing and Chuck Smyth, our VP Controller.

Before I get into the presentation our attorneys have asked that I share with you the following Statement. Statements regarding future financial performance and results and other statements that are not historical facts contained in the release are forward-looking statements that involve risk and uncertainties including but not limited to market factors, market price of natural gas and oil, results of future drilling and marketing activity, future production and cost and other factors detailed in the company's security and exchange commissions filings.

Moving to Cabot's quarterly results, year-over-year, comparisons as we are aware, continue to reflect lower realized prices for natural gas, which accounts for about 80% of our production. While this was our best quarter so far this year, with a net income of $6.1 million and discretionary cash flow of $45.5 million, it still remains unfavorable to the first - to the 2001 3rd quarter, which had a net income of $10 million and a discretionary cash flow of $64.3 million. As was the case last quarter, we once again see similar year-over-year comparisons throughout our sector, from the continuing effects of last year's robust prices. However, the comparisons are starting to improve as we're all aware.

In contrast to pricing results, our production has remained consistently higher than our rates reported last year. Due in part to increased oil production from our field in south Louisiana and also from the contribution from the Cody acquisition, in particular our McIlhenny well in Avery Island. I am please that four of the last five quarters, Cabot has seen sequential increases in our production, including the third quarter, which was 2% higher than our second quarter of 2002. This figure includes the impact on production as a result of hurricane Isidore, which for several shut-ins of our gulf coast wells in the effective area for a period of two to three days. This did result in a production loss or delay of approximately $150 million cubic foot equivalent.

Cabot, like many of our other peers, who operate in -- in the gulf coast area of Louisiana, experienced additional production losses early in the fourth quarter, due to hurricane Lili. At this time, Cabot estimates that 320 million cubic foot equivalent was lost over a four-day period as a result of Lili. We also incurred about $1 million in physical damage to facilities out there but were insured with a $250 deductible. -- $250,000 deductible, I should say.

In terms of production forecast, our guidance at this time remains basically unchanged from the numbers we gave at the end of the second quarter. And I will outline those for us. On oil, Gulf coast, we estimate 7,500 to 7,750 barrels per day. In the east, 95 to 100 barrels per day. In the west, 450 to 550 barrels per day. For a total of about 8,050 to 8,400 barrels per day. On natural gas in the Gulf Coast, guidance is 75 to 80 million cubic foot a day. In the east, 47 to 49 million a day. And in the west, 66 to 70 million cubic foot a day. For a range of 188 to 199 million cubic foot per day.

With regards to pricing, and we're pleased with the direction of pricing, but comparisons to last year as I've mentioned, natural gas prices are rather disheartening. We realized a 277 per Mcf this year, which is down $1 to the third quarter in 2001. Our hedging position for natural gas, which we put in place early this year had expired in August however, it did reduce our gas price 3 cents per Mcf for this quarter. Our costless collar had a 254 per Mcf floor and a 317 per Mcf ceiling on a [inaudible] equivalent basis. On our 4,000 barrel per day oil collar arrangement, which is in place through December, it is reduced our realized oil price by $2.52 per barrel for the quarter. Both the hedges both of the oil and natural gas hedge put in early in 2000 we're really defensive in nature and designed to ensure the ability for us to implement our capital program for 2002, which we obviously have been able to do.

Conversely, our recent hedging activities more offensive in nature, which we prefer. With the focus on locking in prices that exceed traditional levels for this -- for this business, as the press release highlighted, we swapped a portion of our Gulf Coast natural gas volumes. North of $4 per Mcf for all of calendar year 2003. And on the oil front, we're about 35% hedged as previously disclosed. Going forward, we do plan on actively managing this hedge strategy and we will layer in incremental volumes of both oil and gas as the opportunities arise.

We reported lower operating expiration in G&A expenses for the third quarter of this year, compared to last year. For really a couple of reasons. Primarily it is our focus on cost and also a significantly lower expiration program in 2002 versus 2001. Some guidance for the remainder of the year, we anticipate operating expenses to average 57 cents per Mcfe. Taxes and other income, 38 cents per Mcfe and interest expense, 28 cents per Mcfe. Expiration expanse for the full year is expected to total approximately $40 million. That is up $5 million from previous guidance due to our expanded 2002 drilling program. G&A we anticipate remaining at $25 million excluding the cost associated with the second quarter CEO retirement.

Operationally, the program has been increased primarily in our Gulf Coast region. Between now and the end of the year, we have 29 wells scheduled. A couple of those, which are new wells, to identify a couple of the key projects between now and year-end. And all of these are Cabot operated. In the Gulf Coast region, we have the [inaudible] well, which we have discussed. It is a well we have 33% expense interest and a 30% working interest. We anticipate a December spud on that. Fairly significant prospect, 75 to a couple hundred Bcf unrisk. It's a 4.7 million dry hole cost gross. We do anticipate that well probably to be statused, though, into 2003, with the length of drilling.

We also have our East Cameron 89 well, it is offshore. Exploratory well. We have an expense interest of 48.6%. Working interest of 42%. We will spud that this month. It is a -- has large potential, depending on the amount of sands and levels you put in it. Anywhere from 25 to 200 bcf-type prospect. $7 million draw hole 88. We also have in South Louisiana, the Hayward prospect. We have a expense interest of 37.5% with working interest of 50%. We're currently building location on this well and it's a 15 to 40 bcf-type prospect with a gross dry hole exposure of $2.3 million. We have -- more much an exportation well in South Texas, our Harbor City no. 2. Earlier this year we had our exploratory discovery down there on the Harbor City no. 1, this is drilling additional fault block down there. We have 56% working interest. It's a $5 million dry hole gross exposure for us.

And the last ones, we will identify as a -- as a -- a key well for us between now and year end is Northwest [inaudible] in south Louisiana, also. We have a working interest of 25% in this particular well and we are currently rigging up -- excuse me, it's 25 to 75 bcf type prospect with the 400 million gross dye hole expense. These wells I've outlined will expose Cabot anywhere from 48 to say 180 bcfe of net unrisk reserve potential and our expense is -- is a little bit less than $10 million on these wells.

Our decision to add to this year's program really comes in part because of the outside opportunities that we were able to evaluate and take advantage of and also for the fact that -- in the service sector, the prices have remained competitive and we're allocating additional capital because of that. We're hopeful that this remains true for next year. We have outlined a preliminary capital program of $150 million. Our 2003 program will expose the company to significantly more upside than we were exposed to in our 2002 program. I will say, however, we will stay consistent with our -- with our strategy that if we do see a blow-out in service calls to rig rates, we will certainly evaluate the best use of our capital at that time.

As I reflect back on this past year, I see Cabot pretty-well positioned for future growth opportunities and I think we have also realized incremental value on each unit produced. I think our 2000 program at the end of the year will achieve our expected results of reduced [inaudible] cost. I think we will see reduced all-in cost and we will also see a reduced overall debt position. Looking at our 2003 program, I think we continue to position the company well for -- with our growing prospect inventory. We're exposing ourselves to additional opportunity with Gulf of Mexico prospects. We continue as I've mentioned before evaluating Canada for the long-term. With our increased capital program, again, with considerable more upside exposure on the expiration side we had to look forward to. We will balance this expiration exposure on a unit basis similar to what we are seeing in 2002.

I think additionally in 2003 I think we will accomplish one of our 2002 goals, which we also have in 2003, of a continued debt reduction program to strengthen our balance sheet and as we go through 2003, we will continue to talk about some of the exciting projects we have in each of our regions. With that, Clay, I'd like to turn it back to you and we will be happy to answer any questions. The audience might have.

Thank you. The question and answer session will be conducted electronically. If you would like to ask a question, please do so by pressing the star key, followed by the digit 1 on your touch-tone phone. If you're using a speaker phone, be sure your mute function is turned off to allow your signal to reach our equipment. We will proceed in the order you signal us and take as many questions as time permits. Press star 1 on your touch-tone phone if you would like to ask a question. We will take our first question from Ellen Hannah with Bear Stearns.

Thank you. Good morning. Dan, a few questions on the expiration program that you outlined. One, do you operate any of these wells as a four or five here that you talked about?

Yes, Ellen, we operate all of those.

Okay. And I may have misheard you, East Cameron, 39, were you at a 42% working interest? Did you mention that the range, the predrill is 25 to 200 bcf?

Yeah, let me back up on that. I'm sorry I didn't speak very clearly on that. That is East Cameron 89 --

89, sorry. My hearing is probably going!

And we have a working interest of 48.6% and that before [inaudible]

Okay

And after that we have a 42% interest and we do anticipate spudding that, Ellen, this year.

And is the prospect size 25 to 200?

That's correct.

Okay. What's your kind of your likely estimate, I mean that's a pretty broad range.

Yeah, it is a broad range and depending on the number of levels that might be productive, we have a -- a piece of [inaudible] anywhere from 25 to 30%.

Okay. And do you -- one thing you didn't mention was anything that you might be doing in the Rocky Mountains, either in the fourth quarter or looking into next year.

You know, we have looked at the Rockies this year and certainly since I guess May, June, with the basis blowout up there, we have reallocated some of the capital out of the Rockies. We've put some in the mid-continent and we have not -- in light of where basis is at this time, we have not made a decision to -- to put any additional capital up there.

Okay. And lastly, and then I will stop here, on your $150 million Cap Ex program that you tentatively set for next year, can you given us a flavor of what you're looking for in terms of production?

We are continuing to work that 2003 program and on the production guide I think we will be in the middle singe digits.

Okay. In terms of a growth rate.

That's correct.

Okay. Great, thank you very much.

You bet.

As a reminder that, is star 1 on your touch-tone phone to ask a question. We will now we will hear from Sean Reynolds with Petri Parkman.

Hi, guys. Seems to me like you're going to have a decent amount of free cash flow after your capital spend next year. What would be your priority in terms of the use of that capital?

We -- we are going to address our debt position and we will continue to do Sean. We tentatively set this capital program with a $3 gas price and we're going to look at the price as we come out of the winter months. We're going to certainly have an increased program using the $3 price and as we go throughout 2003 we're going to address both our capital program, the opportunities we have in our portfolio, but we're also going to continue to look at our balance sheet to continue to position that in a little bit of lower debt to total cap.

So, you, end of the quarter had a debt to cap around 53% is what I got off of your --

Slightly under that, that's correct.

So, what would you be aiming towards, just under 50 or do you have a goal to get to say 45 or lower?

We would -- we would absolutely love to get below 45. Somewhat dependent upon price, Sean, we're going to, again, kind of -- our fix is going to be the capital program and then how much allocation towards debt is going to be somewhat dependent upon pricing.

Okay. Great. Thanks.

You bet.

Moving on, we will hear from Frank Brakin Jefferies and Company.

I had two questions. First, your guidance is made more difficult than most by -- by the -- the things you have to deal with at [inaudible] You've been kind of consistently conservative in assuming that field is going to roll over pretty hard. My understanding is that's the source of the decrease gas production. Can you -- can you give us an update, is this -- is the current quarter guidance a continuation of that engineering forecast? And -- or is it -- and maybe a little conservative, or is it -- is it an issue where you're actually starting to see the production declines that we've expected all year and haven't quite materialized yet?

Well, Frank, your -- you're aware of the Gulf Coast wells and how they can be unpredictable and when you have extremely high rate wells like we have at [inaudible], we might air a little bit on the conservative side, but I can say this about the production, we have been pleased with the -- with the way its held up. Certainly we've seen a little bit of decline in the field. We've been pleased with the -- in one particular area, we've been pleased with the consistent high yields per million on that field and that has been reflected in -- in maybe the conservative guidance we've given on the oil side.

Right.

But, you know, when you -- when you have the high pressure wells and the high yields, you do anticipate maybe the yield to come down a little bit, but, again, they've been very robust wells and we've been please we did that.

Gotcha. So, but and the same thing on the gas, the rates holding in but you've got to -- you've got to begin -- you've got to be consistent and at some point in time, you're going start to water out some of these things and it's best to point us in the downward direction.

Yeah, we certainly anticipate that. They've held up well. They do have a -- the reservoirs are, for the most part, water-supported. So, you're seeing not too drastic of declines, but we certainly see a little bit more water yield and -- and we do anticipate a continuation of that and then, you know, once you get down to the end of the life of these things, if you had too much water production you can have mechanical failures that create an instantaneous result and, you know, we're cautious of that, but -- but we've been pleased so far with the -- with the way it's held up.

Great out performance.

Yes, it sure has.

I'd like to pick your brain on one other thing while I have you. There is a lot of -- as I understand it, there is a lot of downthrown about production at East Cameron 89. Can you -- can you tell us -- and as I understand this prospects to test upthrown,, which there is no -- doesn't appear to be a lot of well control in that regard. Can you tell us how your experiences in the [inaudible] area, bias your election to participate in this well?

I tell you what, Frank, I think that Michael Walen is raising his hand over here and we will turn that over to him.

Hi, Frank. It did bias us a little bit in the sense that we thought we could extend the plays offshore and, you know, we did some reasonable [inaudible], if you-and think that in this mini basin that, you know, obviously, we already [inaudible]have it on the downside. We think that the seismic is suggesting to us that there is [inaudible] sands on the upside. So, we're -- we're -- we're hopeful that that model will hold. And going forward, we are going to pursue that model on other prospects in this -- in this same general area.

Okay. So you're really saying this is in a lot of ways an etouffee parlay in the offshore.

Yes.

Thank you.

Delphi Management, Richard Ferhare have our next question.

You grew your production 5% from a year earlier. Can you break that down in terms of what was from acquisitions and what was from the drill bit? I have one question after that.

In the -- in the 5% -- let me go back to on quarter after quarter we had 2% and about 60% of our growth sequentially from quarter-to-quarter is a result of the Cody acquisition --

Uh-huh.

And about 40% is organic.

What about from the previous year?

Yeah, it's the same from the previous year, also, Richard.

Very good. And going forward, is that mid single digits number all from the drill bit or including acquisitions you might make down the road?

No, that's all from -- all from the drill bit. We do not forecast acquisitions into our capital program, nor our -- our cash flow stream.

Okay. And can you give me an update on your approved reserves now on a breakdown of oil and gas?

Let me put my hands on that. All right, I'm going give somebody that has those specific numbers...let's roll to the next question, Richard and before we sign off, we will -- and you wanted it by region?

Doesn't matter so much by region, but just the breakdown of what's oil and what's gas?

Richard, this is Scott Schroeder, our total reserves is 1154 Bcfe. Of that, 90% is natural gas.

All right.

Okay?

Thank you.

As a final reminder, it is star 1 for a question. We will know hear from Alexandra Zortea from Goldman Sachs.

Thank you, good morning. Really only one question left. Regarding your capital program for next year, first of all I guess as I look at the numbers, I mean with &150 million dollars, lets say plugging in three fifty for gas prices you would have at least $50 million left for debt repayment. Can you tell us a little bit how, you know, you came up at that number? I mean was it kind of keeping in mind first of all where debt was going to be? Or was it a bottoms up approach? And what do you think will change that number, given that you've got the hedges in place?

Well, first off, we did do a bottoms up approach and we are in that process right now, Alexandra. We continue to mature our 2003 program. We used $3 and, yes, when you look at the strip, it certainly is on the -- on the low side of our -- of the strip right now.

Uh-huh.

We are also being consistent on not only a conservative approach possibly from our -- our setting up our capital program with $3, but we also are consistent in using that same $3 flat price in our project economics.

Yep.

We continue to look at projects that meet a fairly rigorous pricing environment and also hurdle rate. We -- we want to effect our numbers,, we certainly are looking at our unit cost. We think we will be able to affect our long-term by DDA by having projects that clear the hurdle at a more conservative pricing environment. And we do, though, look forward to, as I've mentioned, layering engine some -- some additional hedges on the gas side in particular as -- as the opportunities present themselves. With that layering in, we will, at that time, as we see the price support a little bit deeper into 2003, and certainly early on into 2003, and then we could possibly give additional guidance on what we might do with our additional cash.

Okay. And as it relates to the -- to the nature of the program itself, you've talked about possibly having more expiration exposure next year relative to this year. Is there any way you can give us a sense and I'm not looking for specific percentages, but, you know, maybe where some of that capital is going incremently, you know, three versus '02 or more exploration, more Gulf Coast?

Well, as mentioned, we're not through with the program, but it is safe to say that the percentage allocation for region is going to be similar as to the allocation in 2002. I would anticipate that from a expiration perspective, that we will more than double the number of exploratory wells 2003 versus 2002.

Okay. And one final question: Embedded in that number, as it relates to getting more acreage and seismic, where, you know, where are you at this point?

In other words, where are we active in acquiring seismic and acreage?

Yeah, I guess the question is over the last couple of years you've been more active on that front.

Right.

And you've been building up more inventory, so, I guess looking at the next two or three years, next three years.

Yeah. Well, we certainly will continue our -- our emphasis on the Gulf Coast, we do anticipate the majority of our seismic dollars will be allocated to the Gulf Coast. The majority of the acreage we have acquired has been in the -- in the west. However, the west does present us a little bit of a -- a decision in the sense of where the basis is and what the basis is going to do up there. I think it is safe to say we might be a little more active in the west if we didn't have such a large basis differential, but we will continue to pick up and continue to position ourselves in the west. We will continue to allocate a majority of our capital in the Gulf region, including our -- our -- our opportunities in the Gulf of Mexico, on the shelf. And we are also picking up acreage in the mid-continent, which we had started this last year and will continue into 2003. And we have implemented a -- and started picking up acreage in the Appalachia, in the east area.

Okay. Thank you very much.

Okay. You bet.

That concludes today's question and answer session. Again, I would like to remind everyone that you may listen to a rebroadcast of this conference at 12:30 eastern today through November 1st at midnight by dialing 719-457-0820 and entering passcode 488719 on your touch-tone phone. And now, Mr. Dinges, I'd like to turn it back to you for closing or additional remarks.

Thank you, Clay and thank you, everybody for their interest in Cabot Oil and Gas. You know, looking forward, I think you can continue to see Cabot change. I think you will see us demonstrate growth through the drill bit as our program gains momentum. We're going to continue to focus on cost containment and -- and our debt position and we will also continue our -- our efforts in the acquisition area. With that, I will close and thank you again for your support.

That concludes today's Cabot Oil and Gas corporation conference call. We thank you for your participation and hope you have a great day.