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Cabot Oil & Gas Corporation (NYSE:COG)

Q3 2007 Earnings Call

October 26, 2007 9:30 am ET

Executives

Dan Dinges - Chairman of the Board, President and CEO

Scott Schroeder - VP and CFO

Analysts

Brian Singer - Goldman Sachs

Ellen Hannan - Bear Stearns

Sunil Gajwani - Catapult

Jack Aydin - Keybanc

Corri Garcia - Raymond James

Michael Schmitz - Banc of America

Larry Benedetto - Howard Weil

Richard Tullis - CapitalOne Southcoast

Presentation

Operator

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.

Dan Dinges

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

Before we start, let me say that the statement regarding forward-looking information included in the press release prior to my comments today. As you saw last night we issued two press releases, both illustrating our continuing 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 removing a small impairment for our North Louisiana field. This level of net income was Cabot Oil & Gas Corp.'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 a $0.40 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 colored range of $60 to $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 of $8 per Mmbtu.

Our focus has been on the Rocky Mountains, were the recent basis blowouts have created extremely low cash prices. Remember our hedges at the sales index points, which includes the basis.

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

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

Moving ahead, looking ahead, this is our traditional time of year to establish guidance for next year. And 2008 is setting up with our capital program to again deliver very good organic growth rates.

I want 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’re reducing our capital allocation, as we wrestle with the net back prices we’ve seen in this place.

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. When compared to some of our peer programs, this level of capital spending versus cash flow may seem a little conservative. However, Cabot's proved organic program will allow us to drill approximately 366 net wells in 2008 versus the 406 wells we anticipate stat using in 2007.

We also expect to be able to deliver over 250% reserve replacement. And oil and finding cost to be around the $2 range, 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 add significant reserves by yearend 2008 at a top-tier refining cost. That's why we're looking for 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're 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 between 14% and 16% for the full year.

Gulf Coast is expected to exceed their current equivalent production levels. So we're 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 west to be within our full year guidance range.

We have reduced our guidance in the East. That's 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 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 smaller impairment of our North Louisiana field. From a guidance perspective, direct operations were outside the range due to the higher level of activity on our lease. Guidance for the next five quarters reflects the dynamics of the market and our expectations.

Now let me move to operations. We have added approximately $100 million as we're closing out the year and took -- 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.

Focus of our 2008 program has been prioritized with increased emphasis on East Texas, which I'll talk a little bit 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, our focus will be in Mayberry and Mississippi, and depending on the natural gas prices and in the Rocky Mountains, the Moxa Arch and some activity in South Texas.

Moving to East Texas and some of the details of our program, the County Line field is drilling out so far extremely well and above our expectations. Drilling efforts almost 26,000-acre prospect has been directed as --- for the most part as horizontal James. We have drilled Pettet wells, and again continues -- both continued to yield exceptional results. To-date, we have drilled 7 horizontal wells, 5 of those in the James and 2 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, following the sales at 12.2 million cubic feet per day. We will be drilling 4 wells between now and the remainder of 2007, and we've scheduled 32 wells for our 2008 program

We are extremely high on this prospect. The field is currently producing at approximately 19 million cubic feet per day, and that is restricted rate due to pipeline capacity. We 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's 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 has been 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 any each well. For 2008, as we gather information in the lightly drilled deeper section in the field, we'll schedule about 12 wells initially for this field.

In South Texas, we continue to see positive results in our McCampbell field. Even though we've 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 other zones behind the pipe. While another Gibson Sign well is flowing approximately 1.8 million a day and 100 barrels of oil from D2 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 overall. We plan to drill at least one more well between now and the remainder of the year.

Finally, we continued 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’ve finished some of that work and some completion work on our most recent well. I can 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 slow down with our issues on nitrogen and the hydrocarbon DuPont problems, and this is one of the reasons for our revised fourth quarter guidance in the east.

However in that area today we've drilled eight horizontal wells and have five of those wells producing though at curtailed rate, 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 come over Bcf each and we are completing these wells at around $1 million. This area certainly has great deal of upside potential once we get it lined out.

Operationally, we continue to work on the nitrogen and hydrocarbon DuPont issues. We have multiple programs out there in the field and new well-tap on the remaining sales line. A J.T. unit we are putting in there, and we anticipate to get all this lined out in the near term.

We have also taken delivery of our new rig, [Speedstar] 185 for work out there in the Hurricane field. This rig is one of five rigs. Our contractor is bringing to cap it in this basin. We plan to drill a couple of more horizontal Herron wells between now and the remainder of the year, and we have a 20 horizontal well program schedule in 2008.

Now I am anxious, there have been the 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 91 wells for our 2007 program.

Historically in that area, we were a little bit delayed in getting to some of those wells in South West Virginia. Historically, in that area we hit a few exceptional wells, and this year's no exception though, they did occur a little bit later this year.

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

Our 2008 budget, has a little bit different mix in the vertical and horizontal wells that we have in total 265 wells scheduled at this time. As mentioned, a number of these wells will be horizontal here on well, and we are also starting a new initiative for us in the deep Marcellus. So, with the little bit of the mix the 20 lower horizontal wells that are horizontal and 19 new Marcellus well that we're going to be drilling. It really equates to our larger program if you compare to our vertical well program that we drilled -- our total program we drilled in 2007. In an equivalence basis, it's equivalent to about 330 vertical well programs. In our new initiate up there in Marcellus to support what we are 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 the turning wells in line. And we are also enhancing some of our compression up there in the East. In the West, exploration continues to be focused on large impact prospects in the ParadoxBasin, the Eastern Utah and Southwest Colorado. We are currently drilling the second well in our McKenna prospect it’s a 770 foot (wildcat) and we will test the Marcellus Shale in the upper Paradox group. The well offset a recently completed competitive well about at mile away which is reportedly flowing at about 3 million per day from Lassa section.

If we are successful the well should set up a significant development program for us where we have about 38000 acres in this plot. A second Paradox Wildcat in has just begun, the South Gibson Leadville Wildcat is at 8000 for test that we expect this week.

The well exposed Cabot to prospect size of about 25 to 100 Bcfe in the Leadville plus additional upside in the S-May in the crack and sandstone

Excuse me in the Moxa Arch area we will face 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’ll 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, as 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 good a 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 cost to be in the $2 plus range.

We have laid down our initial to 2008 program, that delivers similar numbers as our 2007 capital outline. And as I mentioned, with a capital outlay right at our cash flow numbers. 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 will look forward to answering any question the group has, Crystal I will turn it back to you.

Question-and-Answer Session

Operator

(Operator Instructions). Sir, your first question comes from the line of Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs

Thank you. Good morning.

Dan Dinges

Hey, Brian.

Brian Singer - Goldman Sachs

Can you talk more to the backlog in the east region and what you believe is the net production rates ultimately that you can achieve from the 65 wells behind pipe and as you look your ’08 drilling program. Can you talk any further mid-stream risks?

Dan Dinges

Yeah. If you say 65 wells behind pipe, if you bring in, say your average initial turned inline rates over 150, 200 a day. That’s approximately 10 million a day net to Cabot.

Brian Singer - Goldman Sachs

Okay. And do you see, go ahead.

Dan Dinges

Yeah. In our 2008 program we’ve done some things that I think internally have mitigated any risk in our 2008 program. We’ve taken a deep look at our process and our budgeting, whether it'd be the risking, whether it'd be the initial rates. And reserve aspects, what reserves we are 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 in 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 a, as we've 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, we're just lucky in hitting the exact core of the field, we don’t know, but we have taken some of that risk in consideration when we put together our production guidance on those particular wells. And actually we've used about half of the 30 day average that we've seen in these initial wells in our 2008 guidance.

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

Brian Singer - Goldman Sachs

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

Dan Dinges

Well, no in the opportunity areas I was not meaning it from the M&A sides and as you are aware Brian, we have a good organic program that delivering very good growth. 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's 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 master area to increase our activity up there, because we think the basis is coming inline for whatever reason and delivering the cost net back to us that we want to see, then we'll jump up there and we will be prepared to jump there and increase our capital programs without reducing our capital program in the rest of the area.

So it's mainly focused on operations, expansion potentially in the master or if we are able to execute and fulfill some of the drilling expectations in our core areas, we might increase our activity towards the year end 2008, which we have historically by the way done.

Brian Singer - Goldman Sachs

Great, thank you.

Dan Dinges

You bet.

Operator

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

Ellen Hannan - Bear Stearns

Good morning.

Dan Dinges

Good morning, Ellen.

Ellen Hannan - Bear Stearns

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 additionally?

Dan Dinges

Yes, we are.

Ellen Hannan - Bear Stearns

Okay.

Dan Dinges

We've seen what we've been trying to do out there, Ellen, is pick up additional information, if they rank area, the well spacing out there from, say, where we're drilling several of our wells to the closest well. That's been over 20 miles. So the data we're gathering is new data and in different areas of the place. Some areas have not been as encouraging as other areas. But we're certainly encouraged to continue allocating capital to deploy as mentioned.

Ellen Hannan - Bear Stearns

Are you finding anything above the Floyd shale in terms of the [lengths or] depths?

Dan Dinges

Yes, we have seen some interest in the shallower place. And that's why I couch it as a tight sand play in Floyd shale play.

Ellen Hannan - Bear Stearns

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? And you mentioned that reserve potential quote could be substantial, could you sort of put some parameters around that?

Dan Dinges

Excuse me, Ellen. Yeah, sure I will. Let me start first in -- one of the areas with a 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've had got that acreage now part of our field and prospect out there, we were recently -- in fact, we are currently drilling our first well on some of that new acreage. We've accumulated out there adjacent to the acreage we had already had.

And I mentioned our results from our most recent County Line wells that the five County Line wells that we have, horizontal wells in the James right now, the IPs have averaged about 10 million a day. As I mentioned, what we've turned to sales the first 30 days, couple of the wells have averaged over 5 million a day. So that's one area.

The other area is the Trawick Field. It is a large complex we have contiguous. It's probably one of the largest peer contiguous block in East Texas. It's almost 36,000, 40,000 or so acres in East Texas contiguous. And we're 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, 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 CottonValley, the Haynesville, but that's also on the outside of the field proper area anywhere from the Travis Peak down to the Haynesville.

We certainly anticipate, we 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 -- came online between 1 million and 3 million a day each. And we are completing our first operated well in the complex, which is actually on the fridge -- excuse me, on the fringe and not in the field proper.

We are now moving to the field proper area where we're drilling this second well. And we are going to continue to work with the major company and work with the Belmont in 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.

Ellen Hannan - Bear Stearns

And are you carrying the owner of the fields on your wells or what this means?

Dan Dinges

I am sorry, I didn't answer that part. Our entry into the area and be able to get into this large acreage position is carrying the major on like 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.

Ellen Hannan - Bear Stearns

Great. Thank you very much.

Dan Dinges

You bet.

Operator

Your next question comes from the line of [Sunil Gajwani] with Catapult.

Sunil Gajwani - Catapult

Good morning, guys.

Dan Dinges

Good morning.

Sunil Gajwani - Catapult

And congratulations. I have two quick questions. Firstly, 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?

Dan Dinges

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 to 170 Pettet locations in the field also. So we are excited and we are 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 say in the Cotton Valley based on what you've seen a lot of the east Texas is being drilled in the Cotton Valley. We'll have 200, 300, 400 locations in the Cotton Valley alone, and what we are going to be able to do similarly with those wells is when we drill up we are also probably going to take some of those wells down to the Haynesville, as a potential. But we are also going to be able to see as additional take point potentials once we look at the CottonValley, an additional potential in the Travis Peak, the James and the Pettet, and hope to maybe could mingle compellation or plug-back completions in a multi-zone section.

Sunil Gajwani - Catapult

Well that's fantastic. I do have one other quick question on the Eastern region in Appalachia. Not withstanding the nitrogen completion issue that you've talked about, the actual cost per wells and the EURs that you had spoken about in the past have been very encouraging. How would you compare the Marcellus potential and returns on a per well basis with the horizontal that you are drilling in the Devonian?

Dan Dinges

That’s a good question. Without saying a great deal, but certainly saying enough that we were encouraged with our comments, that 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've accumulated acerage 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. 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 a higher pressure 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 are going to be close to that. And though we do expect that EUR could come in above the horizontal wells in the lower [Heron] section.

Sunil Gajwani - Catapult

So just I guess to summarize, if were to just to look at it from the return perspective and I know they are both early stage. It's looks like Devonian Shale has progresses more just because of more time spent on it, but how would compare returns between the two places?

Dan Dinges

Let me just clear this point here. Both of them are Devonian Shale

Sunil Gajwani - Catapult

I meant shallow Devonian versus Marcellus.

Dan Dinges

Yeah, one is shallower, one is deep, and Marcellus being deeper. But I would not just count at all the returns that the Marcellus is going to deliver to us compared to the shallower Devonian. I would discount them. I am optimistic about what we might see out there

Sunil Gajwani - Catapult

Thank you

Dan Dinges

You bet.

Operator

Our next question comes from the line of Richard Tullis with CapitalOne Southcoast.

Dan Dinges

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

Operator

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

Dan Dinges

Yeah Richard might plug back in the queue.

Operator

Okay your next question comes from Jack Aydin with Keybanc.

Jack Aydin - Keybanc

Hi guys

Dan Dinges

Hi Jack

Jack Aydin - Keybanc

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

Dan Dinges

Okay Mike is going to pass on me. I will tell you what, we did up speed with the details. One thing that just now happened is, this happened on September 17 and we don’t have Jeff Hutton here with us today, our marketing guy. But on October 17, we got a new waiver from the pipeline companies which has increased the amount of nitrogen that we were allowed to put into the pipeline, that is going to help and also on October 7th we have let see here, no that's the new waver we got, it has expired on October 7th then we got, the new waver now for 180 days.

Our JT unit, is going to be online. I am started over to buy that I kind of reading from this, Jack.

Scott Schroeder

Yes Jack, the JT unit is installed and online and operating and we got the waver for the end to, from the pipeline and we describe to you a little bit more lining out of some little (mismatch) and that should be slowing at pretty hopefully descent rates here, very soon within a matter of days.

Jack Aydin - Keybanc

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

Scott Schroeder

Maybe 1.5 to 2 million a day.

Jack Aydin - Keybanc

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

Scott Schroeder

No Jack, we have already drilled two additional wells out there this fall. And we are on our third well with that new rig, that Dan mentioned and we kind of drill a couple more after these wells when third one is done.

And then we will pick up, right over in the first year to drill our '08 horizontal program out there.

Jack Aydin - Keybanc

When are you going to give the pipeline in a place?

Scott Schroeder

Well the, 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’re considering laying a line down to the main pipeline systems about 3 to 5 mile south of us. And lay that line down there so we would have to fight with this end to issue anymore.

Jack Aydin - Keybanc

Okay. Thank you.

Operator

(Operator Instructions). Your next question comes from the line of (Corri Garcia) with Raymond James.

Corri Garcia - Raymond James

Good morning guys.

Dan Dinges

Good morning.

Corri Garcia - Raymond James

Hi. Lot of my questions have been answered. But if we head back to the County Line place just a second. The higher rates that you guys are seeing. Can you provide anymore color or I guess how are you thinking about any upside to your EURs that you guys laid out?

Dan Dinges

Well. Corri it's a good question, the engineers we’ve score around 5 if I got too bold with any projections but certainly its rate time on the declines and it’s very, very early in the game with these type of high initial rates. So, where I can 2.5 to 4 basis is in the range of what we ought to expect out of these wells. And it’s still early in the game and is our upside to that kind of depends on, how these wells hold up which would we dictate kind a facture system where we hook up to.

Corri Garcia - Raymond James

Thank you.

Dan Dinges

You bet.

Operator

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

Michael Schmitz - Banc of America

(Question Inaudible).

Dan Dinges

Man I didn’t get all of that, would you…

Chuck Smyth

Michael, you were breaking-up…

Michael Schmitz - Banc of America

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

Dan Dinges

Yeah. 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 of fine number is going to be in the $2 plus range right around that range.

Michael Schmitz - Banc of America

Okay, thanks.

Dan Dinges

You bet.

Operator

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

Larry Benedetto - Howard Weil

Thank you. Dan, in the Timberstar well, which you announced this morning. The length of that was 4600 feet, is that consistent with the other horizontal James lime wells?

Dan Dinges

Yeah, Mike was just saying that, it is consistent with our other wells; our other wells have been right at about 5000 feet.

Larry Benedetto - Howard Weil

And well cost to store around 3.5 million completed.

Dan Dinges

Yes, 3.1 million to 3.5 million.

Larry Benedetto - Howard Weil

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

Dan Dinges

Larry, we're still gathering information, but with the information we have so far, the horizontal would be logical next year.

Larry Benedetto - Howard Weil

And do you have three deals with acreage?

Dan Dinges

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

Larry Benedetto - Howard Weil

Okay. Thank you.

Dan Dinges

You bet.

Operator

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

Richard Tullis - CapitalOne Southcoast

Hey, good morning. How is it going?

Dan Dinges

Great. Thanks.

Richard Tullis - CapitalOne Southcoast

Most of my questions have been answered as well; I just had a couple of more on the County Line wells. The latest win to Timberstar, number one, how long is that been on?

Dan Dinges

Less than a week.

Richard Tullis - CapitalOne Southcoast

Okay. Which is producing right now?

Dan Dinges

Well, as we turned it in land at 12 million a day and well we had to do to turn it inline in 12 million a day was cut the other wells back a little bit.

Richard Tullis - CapitalOne Southcoast

Okay.

Dan Dinges

Because we have 19 million a day capacity right now.

Richard Tullis - CapitalOne Southcoast

I see.

Dan Dinges

So, I couldn't answer you exactly what its 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.

Richard Tullis - CapitalOne Southcoast

Sure. What will be the cost on that one?

Dan Dinges

Little over $3 million, right at $3.5 million.

Richard Tullis - CapitalOne Southcoast

Okay. And that was one to seven stage frac if I remember right.

Dan Dinges

Yeah.

Richard Tullis - CapitalOne Southcoast

Pretty long lateral. And jump into the Floyd rig any rates that you can give us on any recent test?

Dan Dinges

No, we are not talking about that at this stage.

Richard Tullis - CapitalOne Southcoast

Okay. Alright. Well that's it for me today. Thanks so much.

Dan Dinges

Alright. Thank you.

Operator

At this time there are no further questions in queue.

Dan Dinges

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

Operator

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

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Source: Cabot Oil & Gas Q3 2007 Earnings Call Transcript
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