Coterra Energy Inc (CTRA) 2005 Q3 法說會逐字稿

Good morning, my name is Mary Ann and I will be your conference facilitator today. At this time, I would like to welcome everyone to the Cabot Oil & Gas third quarter conference call. [OPERATORS INSTRUCTIONS] Thank you. I will now turn the conference over to Dan Dinges, Chairman, President and CEO. Sir, you may begin.

Thank you, Mary Ann. Good morning, thank you for joining us for this earnings teleconference call. With me today are several members of our management team -- Mike Walen, our Senior Vice President, Scott Schroeder, our CFO. Jeff Hutton, our VP Marketing, and Chuck Smyth, our VP Controller.

Our attorneys have asked that I share with you the following statement: The statements regarding future financial performance and results and the our statements which are not historical facts made during this teleconference are forward-looking statements that involve risks and uncertainties including but not limited to market factors, the 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 commission filing. All non-GAAP financial measures discussed during this conference call have been posted to our website at www.cabotog.com. Along with reconciliation to the most direct comparable GAAP financial measures.

Last night, press release together with the October 12 release, highlight many positive aspects of Cabot's business. Most impressive is the production growth we see in our West region, Canada, and the double digit production increases we see in our East region. Not only does the production increase in the East highlight its increasing value, Chesapeake's recent acquisition that I'm sure you all heard about of CNR [INAUDIBLE] also reinforces the value of having an impressive East portfolio such as Cabot's. On the strength of the East performance and contribution of all the other regions, Cabot had another milestone quarter reporting net income of $33.8 million or $0.69 per share. Discretionary cash flow levels for the period also saw historical highs of $92.9 million.

While we are pleased with the progress, the hurricane impact which we are very fortunate is minimal, did remove approximately $4 million or $0.08 per share from the quarter's results, due to the deferred production. For the quarter, realized natural gas prices were 34% above last year's third quarter, and realized oil prices were 44% greater. The impact of hedging on the quarter was a reduction of $1.26 per mcf for expired natural gas hedges, and for crude oil, the impact was a decrease of $14.59 per barrel. We do look forward to the near-term expiration of these positions.

Additionally, as mark-to-market table in the press release highlights, our future hedge positions that require mark-to-market accounting treatment reduced natural gas revenue by $400,000 and increased our quarterly oil revenue by nearly $2 million. Cabot remains about 40% hedged on its equivalent production for the remainder of 2005, and for 2006 we have approximately 28% covered by hedges, which are detailed in the company's website. All hedge transactions for 2006, I might mention, are wide collars that establish floors at seven-plus dollars and also preserve the upside. I'm also happy to report that after a detailed review, the deferred volumes from the hurricanes did not impact our hedge accounting treatment, which I know is a significant issue in the industry at this time.

We do have approximately 9 million per day still shut in as a result of hurricanes, all are nonoperated offshore production. The majority of that production is waiting on downstream repairs. In terms of expenses, all categories fell within guidance range, except for taxes other than income, which was higher due to the significant price move during the quarter, while the rest of the expense categories were within the range indicated in our guidance, all were close to the top end as the industry continues to experience cost pressure in all aspects of the business. In terms of our balance sheet, during the third quarter we funded $60 million for property acquisition, and another $23 million for income taxes, combine this with the traditional ramp in our drilling program in the third quarter, had us borrow $10 million on our line of credit. $240 million of capacity remains on this $250 million facility.

In addition, the company made a decision which has no impact in the current year and minimal impact in 2006, related to stock options. This decision was accelerated -- was to accelerate the remaining tranche of stock options before the FAS123R adoption. The new standard creates an extensive administrative burden required for initial valuing, then tracking individual options, because Cabot moved away from options for employees after 2003 and for directors after 2004, the number of shares impacted is less than 225,000 in total, most of which vest in the first seven weeks of 2006 anyway.

Moving to the operations, production side of our business, the success of our drilling program for the third quarter reflects the nature of our low-risk development and exploitation strategy for 2005. The program has yielded 97% success rate on 88 wells drilled, with a 100% success in the East. Today, we have 29 wells completing across our regions, along with 15 operated rigs, plus three outside operated rigs drilling. In our East operation, we're well on our way to completing our largest program of nearly 200 wells with 152 wells at total depth so far and we currently have eight rigs drilling in the field.

Our year-to-date results have exceeded our budget reserve expectations in the East. Also, our production is North of 60 million cubic feet per day at this time. The focus for our 2006 program is to increase our East program with an initial plan of 240 wells with a peak commitment of 12 rigs during this program. Again, a very active year scheduled for the East next year. Moving from the East to the West, as highlighted in the October 12 press release, the West region also has made good turn around in its production profile.

In the Rocky Mountains, the focus remains on the expanded and accelerated development, drilling in the Mox Larch, Lookout Larch and Double-Eagle fields. We will see 22 gross wells drilled over the remainder of the year with four of those operated by Cabot. Our working interest in those 22 wells range from 10% to 100%. The most impactful resource exposure between now and the end of the year is in our -- is in the Paradox Basin where we will have three wells to drill. One is the Ham Creek which is in [Cana] joint venture well. Two others are in our Double Eagle Field

For 2006, we're increasing our drilling activity in the West by 10% to over 80 gross wells. One of the most impactful wells to look forward to in the 2006 campaign will be the Nelson Creek Wildcat where Cabot will have 100% working interest in this 75-plus bcf prospect. The plan for the West region is balance throughout the year as we continue to focus on managing the region around the drilling stipulations. We gave a comprehensive update to our North Louisiana effort earlier this month. The two things I can't add at this time are that we are -- we have reached total depth on our Loggy Bayou, #16-1, our fifth well in the Eros prospect. We have set pipe and we are waiting on the frac cruise that should come in about a week and a half. Cabot has 100% working interest in this well. The rig which is drilling the 16-1 will be moved to our recently acquired Vernon Field Property and inspite our initial well there by October 7. Also, excuse me, November 7.

Also, we have tested and turned the Loggy Bayou #9-1 well to cell yesterday, it is flowing 4.5 million per day at 4250lb flow casing pressure. Cabot has an 87.5% working interest in this well. Moving to East Texas, particular interest is the spud of our Harrell Number 1 well, which is our first well in our Mendin Prospect, in Rust County, Texas, this is all in the acreage that we acquired in third quarter from a major. This Cotton Valley well is the first to test this 3400-acre block in the Cotton Valley Trend in East Texas.

In South Louisiana, Cabot has successfully completed the CLNF21-1. It was a 6,058-foot Wildcat drilled to test the Willy-Anna Sand Stone, Cabot has a 100% working interest in this well and recently tested it, flowing at 3.3 million a day and 757lb flow tubing pressure. We expect to have this well placed on production by January of 2006. Moving to offshore, our operations on our East Cameron 111, Number 1 well, offshore discovery out there, where Cabot has a 50% working interest, that operation has been delayed due to the Hurricane Rita. We are waiting on regulatory approval to lay our pipeline and install our deck. Compounding this delay is the difficulty in locating equipment, as most of you might suspect, it's tied up with hurricane repair work.

At this point, we're forecasting initial production around the first of the year but that may be rolled back, depending on how soon we can get the equipment out in the field. As we have previously discussed, our goal has been to migrate our Gulf Coast portfolio and our capital allocation to a more resource-dedicated play in order to mitigate a portion of the typical steep declines of the Gulf Coast. Knowing that this would create near-term production challenge as we make this transition, for 2006 we will remain consistent with this strategy. The region will drill 46 gross wells, nearly all focussed on north Louisiana, East Texas, our South Texas and West Texas fields. However, with this program, our expectation is that the Gulf Coast will turn to growth in 2006.

Moving way north, Cabot's Canadian region continues to have great success at our Musro Field, where we have a 24 to 40% working interest. We plan to drill one additional well in 2005, and plan five wells in our 2006 program. Currently, the field which we discovered this year, the field is producing approximately 13 million cubic feet per day, at a restricted rate from five wells. We also have one well waiting on completion, and one rig in the field drilling. We also are preparing in our Canadian region to spud our next exploration well, the Narrow Way Ero Wildcat in November. This is another in a series of deep basin prospects located in Western Alberta which we are pursuing. Working interest is 63% in this Wildcat during 2006, we will be drilling four additional Wildcat in the deep basin tight sand gas plays.

Key wells to look out for between now and the first quarter of 2006, three in Canada, Bolton, the Sutton, and the Cypress are our project names. We have working interest ranging from 50 to 100% in those three wells. We also have our North Louisiana Caster well, which we pushed back into 2006 as a result of moving our bat rig that we had planned for that particular prospect into our Eros area. We'll have a 75% working interest in that Hasten Cotton Valley Wildcat. We'll have an offshore well where we'll have approximately 35% working interest in Highland 173, and the Nelson Creek in our West region, the Paradox that I previously mentioned where we'll have 100% working interest. It's going to be good reserve exposure for those six prospects.

With our expanded leasehold effort and general industry conditions, Cabot has moved its capital program to $400 million for 2005, and 2006 without any M & A activity budget, the initial plan will place a capital program at $380 million. This includes 285 million for drilling and dry hole, 39 million for facilities and pipeline, and 25 million for lease acquisition and seismic. And 9 million for capital work-over. With this program, we expect to continue to grow and expand our reserve base along with an expected increase of five to 10% organically year-over-year in our production.

With that being said, the fundamentals of our industry remain very strong, near term with the constraints of the hurricane supplies, the supplies as a result of the hurricanes in the Gulf, coupled with the onset of winter, there's certainly potential for the energy sector to make another move and I feel strongly that Cabot is very well positioned for its shareholders. With that summary, Mary Ann, I will move to answer any questions the audience might have.

[OPERATOR INSTRUCTIONS] Your first question comes from Eric Hagen of First Albany Capital.

Good morning, gentlemen. My first question is for Scott, if he's there, and it's on the compensation expense, the stock compensation expense that's lumped into G&A. And my question is -- How recurring is that? Is that a variable expense that's related to your stock price? And how predictable is it from quarter to quarter?

Eric, in our guidance that we put out there, you'll see the G&A number has gone up. In the '06 guidance as we had in the '05, we try to capture an estimate for that compensation expense within that category. In the press release, we do break it out, but most of that is variable. It relates to performance shares. Dan mentioned that we moved away from stock options a couple years ago, and we moved to performance shares, and we have to do a calculation, it's against our peers how we're performing against our peers. And so we do that calculation every quarter and we have to true up. And with the volatility in the stocks, it is -- it's tough to predict with any degree of certainty each quarter.

Right. I've seen, I think most of your peers are just -- are kind of backing that out and giving an estimate of, I think, recurring earnings outside of that. Do you plan on doing that or not? Or can we -- assuming we should back out, is kind of the question?

We haven't thought about that. We can think about breaking that detail in our guidance out. Right now, next year's G&A target is kind of between about $30 million, I would say, without the compensation expense.

Okay, great. I just had two other quick questions. In Appalachia, in the shale wells your drilling, have you ever drilled any horizontal wells, and do you think that your acreage is perspective for that?

Eric, it's a great question. And we are at this time evaluating the horizontal drilling up there. The program that I mentioned that has given us double-digit production increases on this current 200-well program, are all vertical wells.

We do have a program that's in place and in progress that is evaluating the potential of not only horizontal drilling, but other efforts to extract greater volumes, not only in reserves, but in production from the shale in the East. We do strongly feel like the geology and the shale are conducive to horizontal drilling up there. It's just typically in the East you drill vertical wells, and not many horizontal wells. But that is part of our program going forward, and we're excited about the potential it could yield.

Okay, great. Just one other last quick question on Canada, just if you could requirement as to how much acreage you have up there, and if you have an idea of how many sort of future prospects you have to drill, what your inventory's like? And are these more sort of structural in a sense, the targets? I mean, how kind of repeatable would the drilling be up there?

Eric, let me back up a little bit to help answer, because I don't have the specific acreage figure we have. What our strategy is and has been and we've been successful, is to JV with companies that have a large acreage position, and drill our way into those positions. And we have been successful in doing that. We would anticipate drilling, oh, 10 to 12 wells in the -- in Canada, in 2006, and in each of those, we feel like is going to have a substantial acreage position to go along with it, where if we were successful, that we'd have running room. And that is exactly part of our strategy. They are not peer structural plays.

We have strike that to graphic nature to some of our plays in the Musreau area, for example, which is northwest of Andarko's wild river complex. It's a similar strike that to graphic as to what they're finding down there. And we've been successful where we have multiple sands in the section. You might get one good sand and one -- or multiple sands in one well, a couple of good ones, a couple of not as good, the next well, it might just be reversed. That's the straight nature of where we're drilling. We have probably on a gas, eight significant projects, and three to 12 sections per project.

Okay, thanks a lot.

Your next question comes from Ken Carroll of Johnson Rice.

Hey most of my questions have been answered, when I look at the guidance you posted on the website, it looks like you might have pulled back a little in the East and pushed back the West region.

I'll let Mike talk about that.

Are you talking about capital spending?

No, production, Q4.

From Q4, on the -- in the eastern region, this is just an issue of timing of the wells in the East. We made a change, a little bit of a change during the year where we deepened a lot of our wells to pick up more shale potential. So we're allocating some of our dollars to drill in these deeper wells. So we aren't drilling as many wells as we had planned so that has an impact on the production.

We've also had a delay in a small field that we purchased to get a right of way to lay a line to make -- to get the production out of that field. That problem has been solved and we should be getting that right of way signed this week, and laying that line very quickly. So we should pick up some production hopefully by the end of the year off that little acquisition that we made.

The Western region production guidance is up and over '04. Because of just the -- that group has had an extremely good year finding better than average wells in Oklahoma, and also our joint program in Wyoming and Colorado has also shown better than expected results.

Got you. Great, thanks very much, guys.

Thanks, Ken.

Your next question comes from Greg [INAUDIBLE] of Tally.

Good morning. Could you just fill us in, provide a little color in terms of the shut-in and timing there?

Well, it's approximately 9 million a day. We have our Britten Sound 41 is one of the projects that shut in, and it's approximately 3.8 million of that shut-in. And we have a Eugene Island 280, a Pogo-operated facility, which is also shut in and a Eugene Island 277 complexes that shut in.

We are not getting a lot of clarity on the timing of our downstream repairs. I would hope that between now and in the end of the year, we'd get some of that back, but, Greg, I'm hesitant to say because it's just extremely difficult on getting clarity on when they might come back on.

Okay, fair enough. Could you talk about your you think you'll be in terms of your reserve base that you're in, based on -- I know you've had a great amount of success in terms of drilling this year?

We would -- we think we're going to be maybe a plus or minus 180% reserve replacement in our program this year. We have had a very good year, and as I mentioned, the East is showing better than anticipated reserve bookings per well, and part of that is a result of what Mike just mentioned, the deeper drilling where we're looking at some additional shale, and we are completing in those additional -- the wells that we're deepening. Again, in the vertical section at this time, and we look forward to exploring further ways of enhancing both instruction and reserves up there. But overall, the company is, I would say, at least 180%.

Okay. Could you then just fine-tune that a little bit in terms of regionally what you think reserve replacement will be?

I don't have that on my fingertips.

You don't need to quantify it but --

Yes, in the East with -- and it's kind of a direct -- directly proportionate to the decline curves. In the East, we are able to replace probably three or 400% in the East. In the Gulf Coast, we are -- let me see here, Mike has this sheet here, I might be able to do a little bit better than speculating. In the -- let's see, this is in the Gulf Coast region, we are about 130 to 140%. In the West, we're a hundred -- in the Rockies portion of the West, we're 130% or so, and --

I'm sorry, what was that?

About 130% or so in the West.

Okay, all right. And then what's current production at?

Current production, we are, as of today, today we're approximately 122 million equivalent today.

Okay.

Excuse me, let me add a 2 to that. 222million.

Right.

Just drop a hundred million there.

Okay. And in terms of any divestitures you're thinking about in this environment?

It's a great environment, both on the sell side and to rationalize your asset and your portfolios. We're not -- we don't have any of our properties on the blocks right now. Our strategy is set in front of us to mitigate our decline curve that is affected by some of our Gulf Coast production, and mitigating our decline curve, in essence, we're trying to reduce the decline and allow us to employ a great deal more of our capital into growth as opposed to a replacement of that decline wedge. So that's part of our strategy.

We look at always evaluating our asset base and making sure that it fits with our strategy. Right now, with our production profile and the challenge that we've had in our Gulf Coast region, as we shift our strategy from a high rate of return province on the South Louisiana offshore area, to a slower decline area of North Louisiana, we knew we were kind of replacing our capital dollars were going to be finding reserves, and a slower decline production profile, not as prolific on the front end. So we knew we were challenged with trying to keep our production flat.

So during this period, we have not considered selling any of our production. Once we get our base in line in the North Louisiana area, and East Texas area, some of the other resource areas that we're working on in the West region, and also in Canada, maybe that opportunity would be a more appropriate this next year.

Okay. And then in terms of how are you thinking about hedging going forward?

We have put about 28% of our 2006 in hedges. Right now our strategy is to -- and they're more offensive hedges, which we prefer, is to put wide in to where we're going to be able to realize what we think is still the upside in this market.

Okay. Those are hedges beyond what you have on this hedging summary?

No. No, I'm sorry, Greg. Our go-forward hedging strategy right now is we like the market, we're comfortable where the market is. We think there are still some robust periods in the market. Though volatile, we think it's going to be opportunities to see some higher prices in the future. So we do not anticipate at this time to place any near-term hedges on.

Okay. But these '06 hedges you have on the slide from your website, you haven't done anything subsequent to that?

That's correct.

Okay. And can you talk about just some of the wells that you've drilled in Appalachia going deep, in terms of the deeper wells? The results you've seen?

Let me sum it up kind of this way. The majority of our wells in the East have historically been drilled very shallow, very shallow, less than 3,000 feet. More recently, we have started drilling the wells deeper than 3,000 feet to four, 4500, some 5,000 feet, looking at the shale that we didn't drill with a great number of our wells up there historically. So we're looking at the shale deeper, we're completing in the shale and the deeper section, and we have, I think with the results that we've indicated, our reserve bookings exceeding our budgeted numbers going into this program, I think that's reflective of how we feel about the program so far.

Those are all vertical wells?

Yes, those are all vertical wells at this time.

And what kind of production, IP's do you get out of the shale?

About a half a million a day.

Okay. Because that's about -- well, that's twice the rate of what I've been hearing in terms of competitors in that region.

Yes. And Greg, they're typical-type shale wells or any resource play for the most part. They have the initial flush production, they come down to a level and sole out and produce for a long time. We've been pleased.

That's great. Can you just, in terms of marketing Cabot, haven't really seen you at any conferences or on the road at all. Can you comment on that and whether you're going to be reaching out to the street? Because I think you have tremendous value, it's just -- you're doing a great job, just no one really is aware of it.

Well, I appreciate that, Greg. Our year this year was a -- we purposely looked inside at our program and put this transition period in place for us. What I wanted to be able to do is not go out and promise, but I wanted to -- I want to be able to go out and say, Look what we've done. An example of it would be, say, Newfield's announcement in the Woodward area up in Oklahoma. They came out and made a positive announcement in their shale play up there. They have drilled three horizontal wells up there, and they gave the reports of those three results.

In reading the commentary after that release, which was positive, and I think very good for Newfield, but in reading the commentary after those reports, there was a mixed opinion on whether or not it was premature to be able to recognize X amount of what might be potential up there. And that's not unlike what I want to be able to do, is come out of the box when we have the opportunity, is come out of the box and say, We have now put together this program, we can put it in front of you, we can show you actual results, and this is what we expect on a go-forward program.

So with each region having a little bit of a transition in its process, we have purposely not been as active out there on the road because it would have been more arm-waving than being able to point to actual commentary. We are, however, scheduled to present at the B of A conference in a couple of weeks.

Great. We'll see you there. Thanks.

Thanks a lot.

Your next question comes from Larry Busnardo of Petri Parkman.

Good morning, a couple of questions on the Nelson Creek prospect. Can you talk a little bit about the formation depth, cost of the well, things like that?

We will, sir, I won't -- we have recently shot a 3-D out there. We have integrated that now, and in the process of integrating all the mapping changes from the 2-D that we had across the prospect. So I will not say anything that is making our exploration at the table squirm. I'm going to turn it over to him and let him say as much or as little as he'd like to about the prospect.

Okay.

Yes, Larry, it is still a work in progress. We did finish the 3-D, we are doing some cleanup land work so we won't talk too much about it. But it is on and trail Cutler sand stone target, very comparable to our Double-Eagle field, and also comparable to in Canada's Hamilton creek field located just to the north of our prospect. We are, like Dan said, the 3-D has been shot. It's out of processing, and in interpretation now, and we plan to drill the well next year, probably depth in the order of nine to 10,000 feet.

Is this -- is it a first S well or --

Yes, we are right now scheduled to be -- we are dealing with federal lands and right now we are looking at the latter half, the latter portion of the first half.

Okay. And how close is the nearest production, how far away is [Incaness ] field?

Probably say about four to 5 miles north.

Okay. And given the depth, is it a 1.5 million to 2 million to drill, or so, somewhere in there?

Probably closer to 2 million.

Okay. Regarding the Vernon Field acquisition that you recently announced, could you give a little bit more color on that, regarding acreage, number of potential locations that you have and the capital that you plan to spend there in '06?

Well, we picked up -- we had an interest in one of the sections that we acquired. We have -- we also picked up a small interest in another 640-acre unit in the Vernon Field, and we plan on moving our rig that, as I mentioned, that we're drilling in Eros 16-1 over to start our first well there. And that will operate. We have at least, we feel like four, five locations in one of the sections, and we feel like there's potential with success of a couple of more locations. The capital we plan on spending is probably the first well will be about 4 million, 4.5 million dollars including frac.

Okay. Going back to Nelson Creek, acreage position there?

It's in progress so I'm going to turn to Mike, Larry, on that one.

I guess I don't know the details on that -- on the exact amount. Probably on the -- just thinking, probably two to 3,000 acres, something like that.

Okay. So if the first well is successful, you've got some running room and plan to drill more? Do you follow up the initial one, that's the plan?

Yes.

Okay. Dan, could you go back through? You gave a list of kind of six key wells that you're looking at that are coming up, could you just go back through those again?

Yes. One is in the Bolton, what we call the Bolton project, that's in Canada. We anticipate spudding that well in December. We have about a 50% working interest in that. The next one was the Sutton, it is also in Canada. We anticipate a January of '06 spud on that. We currently have a 100% working interest in that particular well. The Cypress project is a 50% working interest well. We anticipate spudding that in February of '06. Caster is 75% working interest, that will be a February spud.

Our offshore well is a 35% working interest right now, and we have that schedule, I'm going to put an asterisk beside this one. We have that scheduled for March of '06, but you're well aware of the damage to the rig fleet out there and the -- and all of the chaos on trying to do repairs. And so, you know, that has to have an asterisk beside it on the timing of that. But right now it's scheduled for March. And then the Nelson Creek, which Mike just mentioned, we plan on in the latter part of the first half.

Okay. And just one last one, the percentage of your gas that's sold bid week, I'm sure it's pretty high, but I'm just looking for a percent that you have?

Percentage of our gas, we have our marketing man here also.

Rough estimate, because of the changes, as we get into the winter term sells from the shorter months and from the summer, just remember that all of our gas is variable market price. So when we talk about spot gas in our mind, we're just talking about 30-day sales versus a winter term sale or a one-year sale. Regardless, it's all market priced. Say, somewhere in the neighborhood of 30%, 40% maybe.

30 to 40% is sold bid week?

Yes, sir.

And the rest being sold on spot?

Net loss, 30 to 40% being sold as spot, 30-day sales.

Okay, got you.

Okay.

Great, thanks for the update.

Thank you.

Your next question comes from Allesandra Zortea of Smith Barney

Good morning. I just have a question on I guess sort of the general sort of production picture. For 2006 you're looking for 5 to 10% production growth, and I guess when I look at the first nine months of this year, even adjusting for the hurricane impact, you were sort of up slightly from last year. Now, I understand that your program is shifting towards sort of more stable and more visible programs, but can you just give us a expense for, you know, sort of what you think really has changed in the -- and actually, as I look at your production guidance, I guess it looks like the Gulf Coast component is going towards the low 40% of the company production versus more than 50% last year.

But can you give me a sense for, A, What you really think have done over the last 12 months in terms of reducing the decline, overall decline rate, or sort of how that's going to change over the next 12 months? And B, I guess what kind of impact, if some of these exploration wells work out, would have on that forecast?

Well, I'll take the first, on the reduced decline rate, you're correct on what our strategy is in moving in that direction. I think one of the things that is noticeable in our production profile, and particularly the Gulf Coast, is that the Etouffee field field does not represent nearly the production in our field as it has in the past. You have seen our runoff on the Etouffee, as large a percentage of our production that that represented, it was, once it starts running out from under you, it's hard to keep up.

Now it is much less percentage of our overall production profile, and the remaining portion of our Gulf Coast production is spread over more wells than we have had in the past. So I think that helps mitigate a little bit the steep, steep declines, though we still have typical Gulf Coast declines in some of our wells. The impact of -- on our production profile of the exploration wells that we have budgeted is a direct function of success. We risk in our forecast, we risked the production profile at the same percentage as we risked the prospects.

In other words, if we think that it's going to be a 20% chance of success, we will put only 20% of what we anticipate the anticipated volumes in our production profile. And that's how we set our guidance. So it's going to be dependent upon our success, and if we are successful, do we find what we anticipated finding?

So is the 5% kind of not assuming much success?

No, it's a mixed -- it's a measured and weighted average success across our portfolio.

Okay. Okay, thank you.

Okay, thank you.

Your next question comes from Greg am Bruce of [indiscernible]

Two quick follow-ups. What do you expect fourth quarter capex in today's environment, and what are you thinking about next year?

Let me get that number. I'll let, Theresa, do you have that exact number? Total capital for 2005 right now we anticipate in the fourth quarter of being approximately $109 million.

Okay.

And we have budgeted in 2006 for fourth quarter approximately $80 million. In the --

For the full year '06?

For the full year of '06, we have 380-plus million dollars.

Okay. I hopped on the call late, so you may have mentioned that. And with that, in terms of the fourth quarter, today's current gas prices, EBITDA should be up significantly. What are you going to do, are you just going to repay debt with the flow free cash flow?

Well, we certainly have made every effort to ramp up our operations program. We are -- and I think you can see that in the number of rigs, for example, we're going from eight rigs to 12 rigs in the East. This next year we're ramping up and have secured additional rigs in our North Louisiana area for our 2006 program. So our plan is to put as much as we can into our program where we can do it efficiently with the resource and securing the equipment that we need to secure.

We've added this year between now and end of the year, we've added six wells in the East, and we've added 10 recompletion in the shale for December in the east, because we've been having additional success. So we're looking to put it in our program, but there's always the arm wrestle between Scott and Mike on who's going to get the money. And right now, the operations is winning at this stage stage. Because fortunately we do have a number of areas to be able to replace the capital.

But own on that, I'm just trying to look at a year-end snapshot. So with the 109 million of CapEx, you should be very you should have an ample amount of free cash flow even after the hedges?

It's going to be close, with our tax position and it's going to be close. But right now, we -- right now --

Assuming $13 gas, $12 gas.

Well --

Remember, Greg, you have about 40% that's hedged around the $5 area.

Right.

Right now, the outlook for '05 is that our cash flow will equal what the overall program is.

Okay.

'06, at the current strip, we will generate a lot of free cash flow.

Right.

You're right, we will have that decision to make in '06.

Okay.

Keep in mind when we started this year, our program was 280, and we found selective opportunities and took it up to 400. I suspect those same kind of opportunities will exist in 2006. The only debt commitments we have, is we have a $20 million sinking fund payment every November. And once we make that and the revolver is paid off, which we only have 10 million outstanding on, that's not a good economic decision for the shareholder because of the make hole provision in the debt, we kind of let that sit there offer okay, great.

Thank you.

Thanks, Greg.

At this time, there are no further questions. Mr. Dan Dinges, are there any closing remarks?

No, not really, Mary Ann. I appreciate it, and with no further questions, we do very much appreciate the interest in our program and look forward to our report at the end of the fourth quarter. Thank you.

Thank you. This concludes today's Cabot Oil & Gas third quarter conference call. You may now disconnect.