Coterra Energy Inc (CTRA) 2007 Q3 法說會逐字稿

Good morning. My name is Crystal, and I will be your conference operator today. At this time I would like to welcome everyone to the Cabot Oil & Gas third quarter 2007 conference call. All lines have been placed on mute to prevent any background noise. After the speakers remarks there will be a question and answer session. (OPERATOR INSTRUCTIONS) Thank you.

Mr. Dinges, you may begin your conference.

Thank you, Crystal. I appreciate everybody joining us today for the third quarter teleconference. I have Mike Walen, our COO, Scott Schroeder, our CFO, Henry Smyth, our VP and Controller with me today.

Before we start, let me say the statement regarding forward-looking information included in the Press Release is applied to my comments today. As you saw last night, we issued two Press Releases, both illustrating our continued success. One was the financial highlights for the quarter, and the other reporting achievements in our operations activity.

Financially, the Company again reported solid net income of $ 38.4 million, or $0.40 per share, after you move a small impairment for our North Louisiana field. This level of net income was Cabot Oil & Gas Corporation's second highest for any third quarter reported, only exceeded by last year's record effort. Though the macro environment for natural gas prices was somewhat weak for the quarter, Cabot did experience flat realized natural gas prices versus last year, and that was on the strength of our hedge position for 2007.

Relating to pricing, some of the details, Cabot experienced $ 1.40 per Mcf pick-up for the quarter from the Company's hedge position. This makes the year-to-date pricing pick-up $0.99 per Mcf. For the quarter, oil price realizations fell within our collared range of $60-$80 per barrel, and they were essentially flat with last year. Cabot's overall hedge position is highlighted on our website as you are aware for both 2007 and 2008.

You will note as it relates to 2008 if you looked at it recently, we have added to the position and we have done that when the NYMEX price for 2008 has been above $8.00 per MMbtu. Our focus has been on the Rocky Mountains where the recent basis blowouts have created extremely low cash prices. Remember our hedges are at the sales index point which includes the basis.

Since our reported natural gas prices are in Mcf, we have made a change to our website. We will be converting this metric of our 2008 hedge disclosures on our website to better reflect actual experience, and that is converting the MMbtus to Mcf, however for the rest of 2007, we will show both the MMbtu and Mcf values.

On production, as we anticipated absolute volumes were down between the third quarter's, and that was a result of last year's asset sale. What I remain pleased about is our pro forma production growth of approximately 15% increase over last year's third quarter, and a 17% increase for the year-over-year period. Our production growth has clearly been driven by a 98% success rate in our 359 well year-to-date drilling program.

Moving ahead and looking ahead, this is our traditional time of year to establish guidance for next year. 2008 is setting up with our capital program to again deliver very good organic growth rates. I am going to get a little bit granular with our guidance to help illustrate some of the changes in our capital allocation. Four out of our five areas, the East, Gulf Coast, Mid-Continent, and Canada, will deliver double-digit production growth expectations for 2008.

In the Rocky Mountains, we are reducing our capital allocation as we wrestle with the net backed prices we have seen in this basin. The basis differentials are entirely unacceptable at this time, and therefore, do not allow us to continue allocating a lot of capital in that area, particularly with the opportunities we have in other basins within our portfolio. This event is a good argument to be a little bit diversified.

Our 2008 program was approved yesterday at $490 million, which represents approximately 110 to 115% of our expected cash flow for 2008, compared to some of our peer programs, this level of capital spending versus cash flow may seem a little conservative, however Cabot's approved organic program will allow us to drill approximately 366 net wells in 2008, versus the 406 wells we anticipate statusing in 2007. We also expect to be able to deliver over 250% reserve replacement, and all-in finding costs to be around the $2 range, and 8 to 12% production growth, and have the financial discipline to be at approximately 26 to 27% debt to total cap at the end of 2008.

Additionally we anticipate our drilling program to be about 95 to 98% successful, which is where we are as mentioned in our 2007 program. So in 2008, we expect a low risk program that maintains our balance sheet, and adds significant reserves by year-end 2008 at a top-tier finding cost. That is why we are looking forward to our 2008 program. I have put the cart before the horse a little bit in discussing 2008, however for 2007 full year, with only one quarter remaining we have narrowed our guidance to about where we think we are going to end up, and that is 14 to 16% anticipated pro forma production growth.

Let me discuss the adjustments to our fourth quarter guidance, however as I mentioned we do anticipate the between 14 and 16% for the full year. Gulf Coast is expected to exceed the current equivalent production levels, so we are moving their daily levels higher on the strength, mainly of our East Texas program. We are reducing slightly the West guidance, due solely to the volunteered shut-ins we had out there in October; however for the full year, we expect the West to be within our full year guidance range.

We have reduced our guidance in the East, and that has been a result of delays in well hook-ups, due to weather issues, and we have seen a tightening of the pipeline contractors. The backlog of successful wells waiting to be turned in line has just delayed our anticipated first production. We have 65, approximately 65 completed wells waiting to be turned in line up there, but we do feel like we have solved the problem for 2008 so we won't have a repeat performance. I am not particularly pleased with the execution of this portion of our program, but overall, I am pleased with the drilling results, where we remain 100% successful in our East program.

Moving to expenses, overall, expenses in the fourth quarter were basically flat, after moving the small impairment of a North Louisiana field. From a guidance perspective, direct operations were outside the range, due to the higher level of activity on our leases. Guidance for the next five quarters reflects the dynamics of the market and our expectation.

Now let me move to operations. We have added approximately $100 million as we are closing out the year between now and the end of the year, as capital expansion for our drilling program, and our associated facilities and pipeline infrastructure that is going to help our 2008 program. Obviously with this additional capital being spent towards the end of the year, the impact on 2007 is going to be somewhat limited, but it certainly is going to help us get into 2008.

Our focus of our 2008 program has been prioritized with increased emphasis on East Texas, which I will talk a little bit of detail on each area, the East, and the Mid-Continent. These three areas will drill approximately 56 wells in East Texas, 265 wells in the East, 66 wells in the Mid-Continent, with the Appalachia area included in the 265 wells, will be 20 horizontal wells, and 20 vertical Marcellus wells. Other areas of focus will be in Mayberry in Mississippi, and depending on the natural gas prices and the Rocky Mountains, the Moxa Arch, and some activity in South Texas.

Moving to East Texas, some of the details of our program, County Line field is drilling out so far extremely well, and above our expectations. Our drilling efforts on this 26,000 acre prospect has been directed as for the most part as horizontal James. We have drilled several Pettet wells and again, continues, both continue to yield exceptional results. To date, we have drilled seven horizontal wells, five of those in the James, and two of those to the Pettet. We currently have two rigs drilling, along with completion operations on another well.

Since our last Press Release, we have completed the Timberstar-Worsham #1, falling to sales at 12.2 million cubic foot per day. We will be drilling four wells between now and the remainder of 2007, and we have scheduled 32 wells for our 2008 program. We are extremely high on this prospect.

The field is currently producing at approximately 19 million cubic foot per day and that is a restricted rate, due to pipeline capacity, we have filled up the pipeline quicker than we had anticipated, however we do have operations ongoing in the field right now to upgrade that pipeline, between now and the first of the year.

As you may recall our first horizontal Pettet well has been hooked up, and it has been tested at a rate of 1.2 million a day, and 48 barrels of oil per day. The Pettet has a little bit more oil associated with it than the James, and additional development in the Pettet will occur, as we continue to enhance the infrastructure to take care of the oil, however right now, we are concentrating our efforts on the horizontal James. We have just recently announced our completion of a trade in our Trawick field.

Our deal with a major Company there is being kicked off with the completion of our first operated Wildcat in the field, and we are drilling our second operated well in the field as we speak. This project is going to be a long term opportunity for us. We have targeted gas reservoirs from the James line through the Jurassic Haynesville at about 12,000 feet. We anticipate drilling several hundred wells in this project, with multiple take points in each well.

For 2008 as we gather information in the lightly drilled, deeper section in the field, we will schedule about 12 wells initially for this field. And in South Texas, we continue to see positive results in our McCampbell field, even though we have been developing this field for many years, we have recently completed two very good gas wells from multiple Frio sands.

The Gibson Sign well just came on producing at about 2.2 million a day, plus 200 barrels of oil per day, from Frio section, and we have other zones behind the pipe, while another Gibson Sign well is flowing approximately 1.8 million a day, and 100 barrels of oil from P2 sand, also with behind pipe zones. Earlier in the year, we completed a Flan unit well down there, at about 2.8 million a day and 360 barrels of oil. We plan to drill at least one more well between now and the remainder of the year.

Finally, we continue to evaluate our tight sand Floyd shale play in a large area in the Black Warrior basin of Mississippi. We have finished some of our, actually we really have some ongoing rock geochemistry work going. We finished some of that work, and some completion work on our most recent well. I can't say that we are encouraged, but what we have seen in this most recent well, and we do plan on allocating additional capital in this area for one more well in 2007, and we have additional wells planned in 2008.

In the East, our horizontal lower Herron program, which we call Hurricane, as you are aware this program has been slowed down with our issues on nitrogen and the hydrocarbon dew point problems, and this is one of the reasons for our revised fourth quarter guidance in the East, however in that area to date, we have drilled eight horizontal wells and have five of those wells producing though at curtailed rates, as we continue to deal with the nitrogen issues.

As far as our expectations out there, our first 30 days of production from several of these wells suggest that we anticipate these wells to cum over 1 Bcf each, and we are completing these wells at around $1 million. I think this area certainly has a great deal of upside potential once we get it lined out.

Operationally, we continue to work on the nitrogen and hydrocarbon dew point issues. We have multiple programs out there in the field, a new well tap on the main sales line, a JT unit we are putting in there, and we anticipate to get all of this lined out in the near term. We have also taken delivery of a new rig, a Speedstar 185, for work out there in the Hurricane field. This rig is one of five rigs our contractor is bringing to Cabot in this basin.

We plan to drill a couple more horizontal Herron wells between now and the remainder of the year, and we have a 20 well program scheduled in 2008, a horizontal well program scheduled in 2008. I am anxious, there have been delays in this project, but I am anxious to get this project moving forward.

In Southern West Virginia, in more of our traditional vertical-type sand drilling area, we have two rigs working, and have drilled 56 wells through the third quarter towards a total of 92, excuse me, 91 wells for our 2007 program, and historically in that area, we were a little bit delayed in getting to some of those wells in Southwest Virginia, Historically, in that area, we hit a few exceptional wells, and this year is no exception, though they did occur a little bit later this year.

We have recently completed a well on our Pocahontas lease that tested at 7 million cubic feet after frac, and on our Lyons lease, the well tested at 10 million per day after frac. Both of those wells have recently been turned in line, and are currently producing at about 3 million per day into sales.

2008 budget has a little bit different mix in the vertical and horizontal wells, but we have in total 265 wells scheduled at this time. As mentioned a number of these wells will be horizontal Herron wells, and we are also starting a new initiative for us in the deep Marcellus, so 20 with the little bit of the mix, the 20 lower Herron wells that are horizontal, and 19 new Marcellus wells that we are going to be drilling, really equates to a larger program, if you compare it to our vertical well program that we drilled, or our total program that we drilled in 2007. In an equivalence basis, it is equivalent to about a 330 vertical well program.

In our new initiative up there in the Marcellus, to support what we're doing we have accumulated over 86,000 net acres so far in this area. We will continue to expand our pipeline infrastructure as mentioned, we are allocating some additional capital this year, to get ahead of the programs, so we won't have a repeat problem with turning wells in line, and we are also enhancing some of our compression up there in the East.

In the West, our exploration continues to be focused on large impact prospects in the Paradox basin of eastern Utah and southwest Colorado. We are currently drilling the second well in our McKenna prospect. It is a 7,700 foot Wildcat that will test for the LaSalle shales in the upper Paradox Group. The well offsets, a recently completed competitive well about a mile away, which is reportedly flowing at about 3 million per day from this section. We should, if we are successful, the well should set up a significant development program for us, where we have about 38,000 acres in this block.

A second Paradox Wildcat has just begun. The South Gypsum Leadville Wildcat is an 8,000 foot test that spud this week. The well will expose Cabot to a prospect size of about 25 to 100 Bcfe in the Leadville, plus additional upside in the [Esmay] and McCracken sandstone.

In the Moxa Arch area, we will finish this year's program, and evaluate the movement in the basis pricing to determine our total year activity in 2008. We began the year with a reduced program in the Moxa for 2008 because of the basis. We are very pleased though with our drilling results for our 2007 program in the Moxa, however as I mentioned the basis blowout in this area, we reduced our 2008 capital. Should the environment materially change throughout 2008, we will certainly be prepared to ramp up our program again back up there.

In Canada, the Company is currently drilling ahead on our Hinton 9-6 well. We have reached TD, and we should be logging this well currently, in fact as we speak. For 2008 our program in Canada will mainly focus in the Hinton area, and our Musreau area.

So in summary while we have some well hook-up delays in the East, overall 2007 is going to be a good year for Cabot, and we know our 2007 year-end reserves will be impressive. The organic program has exceeded reserve expectations. We will hit our production targets within our guidance, and we expect our finding costs to be in the $2 plus range.

We have laid out our initial 2008 program that delivers similar numbers as our 2007 capital outlay, and as I mentioned, with a capital outlay right at our cash flow numbers. I imagine if you look at our 2008 outlay as a percent of cash flow, this is going to be one of the lowest in our space. This will allow us to evaluate all opportunities we see throughout 2008, and potentially increase our expectations in regard to reserves and production.

With that being said, thank you for your support. I look forward to answering any questions the group has. Crystal? I will turn it back to you.

(OPERATOR INSTRUCTIONS) Your first question comes from the line of Brian Singer with Goldman Sachs.

Thank you, good morning.

Hi, Brian.

Can you talk more to the backlog in the East region? What do you believe is the net production rates ultimately that you can achieve from the 65 wells behind pipe, and as you look at your '08 drilling program, can you talk to any further Mid-Stream risks?

Yes, if you say 65 wells behind pipe, if you bring in say you average initial turn in line rates of 150, 200 a day, that is approximately 10 million a day net to Cabot.

Okay, and go ahead.

Yes, in our 2008 program, we have done some things that I think internally have mitigated any risk in our 2008 program. We have taken a deep look at our process in our budgeting, whether it be the risking, whether it be the initial rates and reserve aspects, what reserves we were initially assigning, and one of the most important areas is the risking of success, and the timing associated with our risking, and I think what we have done for 2008 is put together what I hope will prove out to be conservative guidance.

We have, for example, in the County Line area, we have 32 wells, several wells scheduled between now and the end of the year. We have 32 wells scheduled in the County Line, which in one particular field, County Line is taking up the largest percentage of capital for Cabot in 2008. It is as we have seen, we have some large initial production rates.

Those wells currently that we have established for the first 30 days are seeing production average for the first 30 days over 5 million cubic foot per day, but in our guidance, because we don't know the full extent of the geology on our 26,000 acres, and as we move out, are we just lucky in hitting the exact core of the field? We don't know, but we have taken some of that risk into consideration when we put together our production guidance on those particular wells, and actually, we have used about half of the 30 day average that we have seen in these initial wells in our 2008 guidance.

So I think we have built in a little bit of mitigation in the risk, and particularly in that particular area, and I picked that because that has a very large impact, because of the higher initial rates coming from that, but I think also in the way we risked our 2008 program, anticipating a great deal of success as I mentioned between 95 and 98% success, we are, I think in a very good position to certainly meet or exceed the numbers.

That is helpful, thank you. You mentioned at the end of your comments that relative low level of reinvestment that you expect versus your peers, and the potential to get a little more aggressive. Did you mean that from an acquisition perspective, and if so, what kind of size and areas would you be looking at?

Well, no, in the opportunity areas, I was not meaning it from the M&A side, and as you are aware of, Brian, we have a good organic program that is delivering very good growth and we haven't focused on the M&A side. If we see opportunities that would be very close to our area of activity, we would certainly look at those, and make every effort to acquire, that is not our focus.

Our focus is really in looking at how well we execute our program through the beginning of the year and if we see the opportunity, for example in the Moxa area, to increase our activity up there, because we think the basis is coming in line for whatever reason, and delivering the cost net backs to us that we want to see, then we will jump up there and we will be prepared to jump up there and increase our capital program, without reducing our capital program in the rest of the area. So it is mainly focused on operations expansion, potentially in the Moxa, or if we are able to execute and fulfill some of the drilling expectations in our core areas, we might increase our activity towards year-end 2008, which we have historically by the way done.

Great. Thank you.

You bet.

Your next question comes from the line of Ellen Hannan with Bear Stearns.

Good morning.

Good morning, Ellen.

I just want to follow-up on a couple of things I want to make sure I heard you correctly, first on the potential on the Floyd Shale. Do I understand you correctly that you are encouraged initially?

Yes, we are.

Okay.

We have seen what we've been trying to do out there, Ellen, is pick up additional information. It is a rank, rank area. The well spacing out there from say where we are drilling several of our wells to the closest well has been over 20 miles, so the data we are gathering is new data, and in different areas of the play, some areas have not been as encouraging as other areas, but we are certainly encouraged to continue allocating capital to the play as mentioned.

Are you finding anything above the Floyd Shale in terms of at lesser depths?

Yes, we have seen some interest in the shallower plays, and that is why I couch it as a tight sand play and a Floyd Shale play.

Another question I had for you, on your recent transaction that you announced about a month or so ago in East Texas with the two major oil companies, can you talk about what kind of commitment you had to give for that, because you mentioned that reserve potentials "could be substantial." Could you sort of put some parameters around that?

Yes, Ellen, I sure will. Let me start first in one of the areas with the major, was in our County Line area. We picked up additional acreage I think it was about 8,000 net acres in the County Line area, and as you can see now that we got that acreage, now part of our field and prospect out there, we will recently, in fact we are currently drilling our first well on some of that new acreage we have accumulated out there, adjacent to the acreage we had already had, and I mentioned our results from our most recent County Line wells, the five County Line wells that we have, horizontal wells in the James right now, the IP's have averaged about 10 million a day, and as I mentioned, what we have turned to sales the first 30 days, a couple of the wells have averaged over 5 million a day, so that is one area.

The other area is the Trawick field. It is a large complex. We have a contiguous. It is probably one of the largest pure contiguous blocks in East Texas. It is over 36,000 or 40,000 or so acres in East Texas contiguous, and we are going to be looking from the James, all the way down to the Haynesville.

The field proper itself which represents a portion of this 36,000 to 40,000 acres is mainly a Pettet field in the shallower section, and a Travis Peak Field. It has been very lightly drilled below the Pettet, and our main focus is going to be below the Pettet in the field proper areas to the Cotton Valley, the Haynesville, but also on the outside of the field proper area, anywhere from the Travis Peak down to the Haynesville.

We certainly anticipate, we have drilled now two outside operated wells on the, where our acreage was contributed to these two wells by outside-operated companies, which were successful in the Travis Peak at between, and came online between 1 and 3 million a day each, and we are completing our first operated well in the complex, which is actually on the fringe, and not in the field proper, we are now moving to the field proper area where we are drilling this second well, and we are going to continue to work with the major Company, and work with them on expanding the opportunities out there.

We need to work with them, because they have some activities going on still in their shallow portions of the field, and we just want to make sure we integrate operations well.

And are you carrying the owner of the fields then on your wells?

Yes, I'm sorry, I didn't answer that part. What our entry into the area and be able to get into this large acreage position, is carrying the major, on like the first eight wells in the area, where subsequent to that, they need to make their election whether they are going to be in or out.

Great. Thank you very much.

You bet.

Your next question comes from the line of Sunil Jagwani with Catapult.

Good morning, guys.

Good morning.

Congratulations, I have two quick questions, first on East Texas with these acreage changes, my guess would be that your location inventory has increased significantly as well as the unbooked potential. Can you frame that for us because I'm not very good at counting acres?

It has increased significantly and we have right now, we think as far as potential in the County Line area, we think we have potential of anywhere from 170 to 220 horizontal locations in the James, depending on what spacing you want to use, and we also have, which I mentioned we are not developing the Pettet at this time, but we also have an incremental 150 say to 170 Pettet locations in the field also, so we are excited and we're going to be out there in that area for an extended period of time.

In the Trawick area, if you look at the Trawick area, and you just do the extrapolations in the Cotton Valley, based on what you have seen a lot of East Texas being drilled in the Cotton Valley, we will have 200, 300, 400 locations in the Cotton Valley alone, and but what we are going to be able to do with those wells, is when we drill them, we are also probably going to take some of those wells downs to the Haynesville as a potential, but we are also going to be able to see as additional takepoint potentials in, once we look at the Cotton Valley of additional potential in the Travis Peak, the James, and the Pettet. And hope to maybe make either co-mingle compellations or plugback completions in a multi-zone section.

Well that is fantastic. I do have one other quick question on the Eastern region in Appalachia. Notwithstanding the nitrogen completion issue that you have talked about, the actual cost per wells, and the EURs that you had spoken about in the past have been very encouraging. What do you think of, how would you compare the Marcellus potential and returns on a per well basis, with the horizontals that you are drilling in the Devonian?

That is a good question. Without saying a great deal, but certainly saying enough that we are encouraged with our comments, we have drilled two Marcellus wells. We are encouraged with what we see in the Marcellus section. We have, actually three Marcellus areas that we have accumulated acreage on. Right now we are looking at the Marcellus as a vertical opportunity for us.

The Marcellus has a little bit greater pressure attached to it, and what the Marcellus is going to allow us to do, we think, is to tweak the completion techniques with a little bit more technology, possibly using higher pressured frac, and possibly using slick water fracs with the Marcellus, which we can't do in the shallower Devonian Shale section, because the pressures are slightly lower, but on a cost per well basis, might be slightly higher than $1 million, but we think we're going to be close to that, and though we do expect that the EUR come in above the horizontal wells in the lower Herron section.

Just to summarize if you were just to look at it from a returns perspective, and I know they're both early stage, it looks like the Devonian shale has more progress because of more time spent on it, but how would you compare returns between the two plays?

Let me just a clarity point here, both of them are Devonian shale.

Right, I meant shallower Devonian versus Marcellus.

Yes, one is shallow and one is deeper, the Marcellus being deeper, but I would not discount at all the returns that the Marcellus is going to deliver to us, compared to the shallower Devonian. I would not discount it. I am optimistic about what we might see out there.

Thank you.

You bet.

Your next question comes from the line of Richard Tullis with Capital One Southcoast.

Hello, Richard. Richard, you might have your mute button on.

Okay, would you like me to go to the next question?

Yes, Richard might plug back in with you.

Okay, your next question comes from the line of Jack Aydin with KeyBanc.

Hi, guys.

Hi, Jack.

Regarding Appalachia, the wells that the horizontal wells that you drilled in Herron that they are waiting for the nitrogen treatment and everything, could you give us a timeline when those wells will be back on production, and is the pipeline timeline to get the pipeline in place, and so you could pick up the drilling activities?

Okay, Mike is kind of passing me, I tell you what. Let me get up to speed with the details. One thing that just now happened and this happened on September 17th, and we don't have Jeff Hutton with us today, our Marketing guy, but excuse me, on October 17th, we got a new waiver from the pipeline companies which has increased the amount of nitrogen that we are allowed to put into the pipeline, that is going to help and also on October 7th, we have, let's see here, we have, no, that is the new waiver we got. It expired on October 7th, and we got the new waiver now for 180 days. Our JT unit is going to be online, I am going to turn it over to Mike. I am kind of reading from this Jack.

Yes, Jack, the JT unit is installed and online and operating, and we got the waiver for the N2 from the pipeline, and we just got to do a little bit more lining out of some little nits and nats, and that should be flowing at hopefully pretty decent rates here very soon, within a matter of days.

Okay, how much volume do we have waiting to be flowing?

Maybe 1.5 to 2 million a day?

Okay, and are you picking up, are you starting to drill now there, or you are going to wait until you get the pipeline in place?

No, Jack, what we have already drilled two additional wells out there this fall, and we're on our third well with that new rig that Dan mentioned, and we plan to drill a couple more after these wells, the third one is done. And then we will pick up right over in the first of the year to drill our '08 horizontal program out there.

But is the pipeline in the play, when are you going to get the pipeline into place?

Well, let me just say that we are looking at this scenario. Depending on how these wells in the first part of '08 drill out, Jack, and complete, we are considering laying a line down to the main pipeline systems about three to five miles south of us, and lay that line down there, so we won't have to fight with this N2 issue any more.

Okay, thank you.

Okay.

(OPERATOR INSTRUCTIONS) Your next question comes from the line of [Corey Garcia] with Raymond James.

Good morning, guys.

Good morning.

A lot of my questions have already been answered, but if we head back to the County Line play for just a second, the higher rates that you guys are seeing, can you provide any more color, or I guess how are you thinking about any upside to your EURs that you guys laid out?

Well, Corey, it is a good question, and the engineers would squirm if I got too bold with any projections, but certainly it is a rate/time on the declines, and it's very, very early in the game with these type of high initial rates, so we are thinking 2.5 to 4 B's is in range of what we ought to expect out of these wells, but it is still early in the game, and is there upside to that? Kind of depends on how these wells hold up, which would dictate kind of the fracture system we are hooked up to.

All right, thank you, guys. You bet.

Your next question comes from the line of Michael Schmitz with Banc of America.

You mentioned for 2008 you were targeting 250% [inaudible] with the $2 finding cost. Can you just update us what you're thinking for this year?

Man, I didn't get all of that.

Michael, you were breaking up.

Sorry. Dan, you had mentioned 250% reserve replacement and $2 finding cost targets for next year. Can you just update us on what you are thinking for this year?

Yes, I am thinking that we are going to be in the 270 or higher range for reserve replacement for 2007, and I think our cost to find number is going to be in the $2 plus range, right around that range.

Okay, thanks.

You bet.

Your next question comes from the line of Larry Benedetto with Howard Weil.

Thank you. Dan, on the Timberstar well which you announced this morning, the [length to the layer] was 4,600 feet. Is that consistent with the other horizontal James lines wells?

Yes. Mike was just saying that it is consistent with our other wells. Our other wells have been right at about 5,000 feet.

Okay, and well costs are still around 3.5 million completed?

Yes. 3.1 to 3.5.

And then in the Black Warrior basin, in '08 do you plan to drill any horizontal wells to the Floyd?

Larry we are still gathering information but with the information we have so far, the horizontal would be our logical next step.

And do you have 3D over the acreage?

No, we don't at this time because it is still such a large acreage position.

Okay, thank you.

You bet.

Your next question comes from the line of Richard Tullis with Capital One Southcoast.

Good morning how is it going?

Good, thanks.

Most of my questions have been answered as well, but I just had a couple more on the County Line wells. The latest one, the Timberstar #1, how long has that been on?

Less than a week.

Okay. What is it producing right now?

Well, we turned it in line at over 12 million a day, and what we had to do to turn it in line at 12 million a day, was cut the other wells back a little bit, because we have 19 million a day capacity right now.

I see.

So I couldn't answer you exactly what it's doing right now, because I don't know exactly what they did on tweaking the other wells, and just balancing everything else out in the field.

Sure. What was the cost on that one?

A little over $3 million. Right at $3.5 million.

Okay, and that was what, a seven-stage frac if I remember right?

Yes.

Pretty long lateral?

Yes.

Jumping over to the Floyd real quick, any rates that you can give us on any recent tests?

No, we are not going to talk about that at this stage.

Okay. Well that is it for me today. Thanks so much.

All right, thank you.

At this time, there are no further questions in queue.

Very good. Crystal, I appreciate it. I thank everybody for their interest in Cabot, and we look forward to continue executing our program. Thank you.

This concludes today's Cabot Oil & Gas third quarter 2007 conference call. You may now disconnect.