Coterra Energy Inc (CTRA) 2008 Q1 法說會逐字稿

Good morning, my name is Jodie and I will be your conference operator today. At this time, I would like to welcome everyone to the Cabot Oil & Gas first quarter 2008 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.

I'd now like to turn the conference over to Dan Dinges, Chairman, President and CEO. Please go ahead, sir.

Thank you, Jodie. And good morning to all participants. Thank you for joining us for this first quarter teleconference call. I have with with me today Mike Walen , our COO, Scott Schroeder, our CFO, Jeff Hutton, VP of Marketing and Chuck Smyth, our VP Controller. As you all are aware our standard forward-looking statements including in the press releases will apply to my comments today. We issued two press releases last night regarding the quarterly financial results and an operational undate with some recent operational successes but more importantly, we gave a road map of Cabot's efforts this year which I will expand on as we go through this call. Financially, the Company reported an excellent first quarter with $57 million of net income or $0.58 per share after removing the expense associated with stock compensation that is driven by FAS 123R evaluations. This level of net income is Cabot's highest first quarter results we've ever reported. Higher production levels and higher price contributed to the increase in performance year-over-year from a clean earnings perspective.

Part of the stock compensation expense relates to a recently implemented employee based retention plan that pays a portion of base salary when pre-determined stock price targets are met. This years stock move caused first target of $50 per share to be met and later exceeded resulting in a $4.3 million first quarter expense for this payment and estimation of achievement of the next hurdle which is $60 per share. I will note that the this plan is for all Cabot employees except for officers. It has been a successful retention tool for us and certainly has motivated our staff. As the press release indicated the result at $50 per share has been over a $1 billion add to shareholder value since we implemented the plan.

Moving to production, earlier in April the Company increased its production expectations for 2008 from 8 to 12% guidance to a 10 to 13%. This increase reflects the in creased capital program particularly in the Rocky Mountains area, the momentum that we saw in the quarter for our February and March, which saw a 10% increase in the daily rate during the first quarter and certainly our drilling results across the program area. With April production averaging more than 255 million cubic foot equivalent per day, we do remain confident that our guidance and the detail we provided earlier in April last night is attainable.

The Gulf Coast volumes remain the same in the second and third quarter with an increase at year-end due to the ramped up drilling activity in East Texas, and in the West, the Rocky Mountain values were increased due to the added capital we saw in the program there, while mid-continent, we left unchanged, and Canada was increased in the near and midterm on the strength of the early year Hinton success. The reduced East volumes reflect a short-term delay in production due to the timing of our West Virginia deepening program to the Marcellus from our typical tight sands we see in our Pineville region. This has resulted in a two month delay in starting up that portion of the forecast stream. We are just starting to recomplete these wells to the shallower horizon. So far, we have about 20 wells waiting to be recompleted.

Additionally, we are experiencing less than expected production associated with our 2007 Hinton vertical Huron Shelf program and in that area, we tried to close space some of these wells. It's an area we've been drilling in for 40 to 60,80 years. We were thinking we could find additional reserves and production; however, we did find more reserves but the production in that particular area did not meet our expectations. In response to the reduced production in that particular pilot program, we're moving 2008 capital allocated to 15 additional system wells to the Marcellus play in Southwest Virginia. And as I will discuss, we will continue to increase our East region focus on the Marcellus. Corporately on production for the production guidance for the fourth quarter, the upper end of our guidance has moved higher and the lower end of our new guidance actually exceeds the previously expected high. This is due to the timing and maturing of many of our programs we have scheduled in the Marcellus Hainesville, James Line, Cotton Valley, Frontier, etc.

Now let me move to the operations update that's allowing us to increase our production guidance. In response to the continued robust gas market, Cabot is significantly expanding its drilling program from the original budgeted program. We now plan to drill approximately, excuse me, 470 wells this year. Today we have 18 rigs running with nine in the East, four in the West, and five in the Gulf Coast. This level will expand to 21 in the next couple of weeks with activity in East Texas, Pennsylvania, and West Virginia. We are working on a program to increase the total rig number to operating to 25 and we will keep you informed on the progress of this acceleration plan.

In the West, getting more regional, we earlier indicated at such time we were comfortable with the net back price in the Rockies for the gas that we would expand our program, with that comfort we have begun to increase our drilling and expect 46 additional wells to be drilled focusing on the frontier formation on the Moxa Arch in Wyoming and the Chester Morrow in Oklahoma. A portion of this increase will be associated with a 40-acre down space pilot program in the Frontier which Cabot will initiate this summer. Cabot will keep two rigs busy in the year in the Moxa Arch area with up to three rigs busy all year in the mid-continent area. An additional rig will be utilized in the Paradox Basin to test our Wild Cat prospects in that area, with this activity expected to start later this quarter.

Moving to to the Gulf Coast, the Gulf Coast will increase program will increase by 18 wells reflecting additional activity in the Minden area which eight wells will be Hainesville test and we will plan to bring in one additional rig to accelerate the activity there. Additionally, we're currently planning to drill about 40 well s in our County Line area with three rigs working throughout the year. We will initiate new expiration activity in Minden, County Line and Trawick in East Texas. At Minden the Company plans to drill a horizontal test targeting the Hainesville section.

At County Line we will drill a vertical Hainesville test which will be the first in County Line to evaluate the Hainesville, and determine the potential of that zone under our large acreage position. At Trawick, we will begin to drill a horizontal James test which we believe will be similar to that scene at County Line. Two of these new initiatives will take place in the third quarter with the third well and third initiative to be spud in October. We recently announced that we have completed already a well producing Hainesville gas and Trawick as part of our eight well earning program which program we plan to have completed by the end of August. At County Line, we will have the new Southeast County Line 12 inch pipeline extension that heads down to the South portion of our acreage finished this Summer. Our late 2008 wells will be drilled along this new pipeline route, as we mentioned last night, three new completions in County Line were 14.1, 17.3, and 16.4 million per day, million cubic foot equivalent IPs and Mike just informed me this morning, the fourth well we had mentioned as completing on last nights report is currently testing over 13 million cubic foot a day and still recovering frac water.

Clearly, the Hainesville as a new initiative, the Hainesville has become another hot topic for the industry and with the plans I just laid out, we will be assessing the prospectivity of the Hainesville in our acreage over the next several months.

Moving to the East, and our program is in transition in the East, more focused on the Marcellus; however, our Marcellus project continues to meet expectations. We will be expanding our activity in both near and normal pressure Marcellus in West Virginia and over pressured Marcellus in Pennsylvania. We're leasing in eight prospect areas in the Marcellus with a significant lease hold position in Pennsylvania. In all, we have over 90 lease brokers currently working in the field. In West Virginia, we plan to drill a total of 77 vertical Marcellus tests to compliment our traditional drilling on our legacy acreage in the play. We had drilled 16 of these wells thus far and completed 14, 11 have recently been turned in line at expected rates ranging up to a 30 day average of about a 0.5 million cubic foot per day. We will have up to five rigs drilling this program in 2008. Cabot has drilled one horizontal well and is the progress of completing this well. This is again down in Southern West Virginia.

Also, we are permitting additional horizontal wells in this area. Where we have completed these wells in the Marcellus, we have fraced only that zone to gain data and gather additional information as we produce just a Marcellus for the time being. Consequently, that delayed and that information gathering has delayed traditional gas production we have behind pipe; however, once we can quantify the Marcellus down here, we will begin to co-mingle these zones immediately once pressure is equalized. We have recently completed our second vertical Marcellus test in northern West Virginia in an area which seems to be transitional between the near normal and the over pressured Marcellus. While we're still in the early stages of testing we're pleased with the initial results of this test so far. This well was drilled 26 miles from our first Marcellus well up in this area which tested at 2.3 million cubic foot per day. Two additional Marcellus tests will be drilled this Summer up in this area. Cabot has an additional 100,000 acres leased under this area not previously discussed.

In Pennsylvania, Cabot continues to evaluate the Marcellus. We have drilled four vertical wells and are currently drilling our first horizontal test. This well spud in mid April and should reach total depth by approximately a week. The third vertical well has been fraced and will be tested shortly in conjunction with a microseismic survey which we initiated yesterday. The fourth vertical well was drilled on the same pad as the horizontal well we have currently drilling. It will be completed after the rig is moved off.

The success we have seen to date resulted in Cabot increasing its program in Pennsylvania by 50%. We plan to drill about 18 vertical wells and 12 horizontal Marcellus wells in Pennsylvania in 2008, utilizing up to three rigs, commencing this month. We are currently in the planning stages for our 2009 program, now estimated at 70 to 100 wells with up to seven rigs working in Pennsylvania. The majority of these wells will be horizontal. We view the infrastructure issues which we've talked about in Pennsylvania to be an important component for the industry in determining how quickly the Marcellus resources can be developed. Anticipating this, Cabot is far along in building a gathering system to get our first gas flowing as soon as possible from this project area. We have our pipeline permit and we've begun right away clearing to commence construction this month. At this time, we believe we'll be flowing gas to sales out of the Marcellus by late Summer on this first initiative in Pennsylvania. Along with this operational activity as I have mentioned, we have an extensive leasing program ongoing in Pennsylvania. Because of our accelerated Marcellus effort, we have elected to redeploy both our human capital and our financial capital away from some of our traditional areas including the hurricane area where we had originally 19 wells scheduled and now only five wells scheduled and we're re deploying this activity to be able to get our arms around the push to the Marcellus particularly in Pennsylvania.

So, with our ongoing program in the new initiatives that we have scheduled, our current $560 million program is well within our current cash flow. We expect at this level to generate free cash. We do have the potential to see the program dollars increase into the future. And we will continue to update you in that regard. Jodie, with that update, I will be happy to answer any

(OPERATOR INSTRUCTIONS). Your first question comes from the line of Joe Allman with JP Morgan.

Hi, good morning, everybody.

Good morning, Joe.

I missed a comment you were talking about a two month delay in 20 wells waiting on completions I think or pipeline. I missed where you were talking about. Could you talk about that a little bit more, please?

Yes, that was in our Southern West Virginia area where we have, that program is in the State of transition, if you will, on trying to make a decision and determination where the best places are going to be for us to deepen some of our scheduled traditional wells on our legacy acreage and where we're going to deepen those wells to look at the Marcellus, and we've done that so far down there in Southern West Virginia where we've deepened about 16 of those wells so far and we've recently turned in line about 11 of them and in doing so, we're wanting to evaluate the results of the Marcellus before we co-mingle plus there's a pressure differential between the shallow tight sands and the Marcellus, so we're going to complete those maybe a little bit longer than we normally would just to get a feel for the decline curve and the profile on the Marcellus, so that is delaying a little bit of the anticipated and scheduled traditional completions we had scheduled down in that particular area.

Okay, that's helpful, and for those West Virginia vertical wells, I think 14 completed and now 11 online. What have been the costs so far on average for those wells?

About the typical wells as we went into the program, the traditional wells without that Marcellus tail was about 400, $450,000 and that's a completed cost. What we're seeing to deepen these tails is about a $600,000 completed cost.

And so it total shallow and deep total is 600,000?

Yes, yes, Joe.

Got you, appreciate it. And then I know that during this first quarter you removed a constraint at, in your James Line program. You got a pipeline on I think in February I think it was. I think 100 million a day capacity. Are there any other constraints that are preventing your production from ramping up even faster than it is and could you talk about do you need to put anymore pipeline in there in the James Line program because it seems like those wells are pretty big wells.

Yes. I'll either pass it to Mike or Jeff, our VP of Marketing to answer something if I forget or don't cover it well, but as you're aware, what our completion technique out there is to have a line run to the location once we TD the well, run pipe, and we start testing, because we're basically fracing and immediately flowing back and in essence going to sales, and with that operation, the bottleneck is not the take away capacity which right now is 100 million a day. If there is a bottleneck on getting there it's a couple of things. One on the marketing side, we have to get the pipeline to locations so we won't let the frac fluid sit on the formation for any length of time whatsoever, so we're concentrating in the area that we can do that and it is a quite an effort to continue to lay these lines to each location ahead of the completion, but also importantly is the level of activity in the courthouse is staggering in both our county areas and what that does is create complications with being able to render title opinions and clearing titles to stay ahead of these rigs. With the Hainesville activity and a catalyst caused by Chesapeake's announcement, it has escalated the activity in the courthouse that our acreage sits in significantly, but with that being said, also this 12 inch line we're laying down to the South, we need to have that line down there also ready to go, pressure tested, and once we move our rig down to the South portion of our acreage, be able to lay the spurs off that main flow line to be able to clean up our completions.

Is that 100 million a day good enough for now or do you expect to expand that some time maybe in '09?

Well, I'll let either Mike or Jeff talk about the operations there.

Currently the 100 million a day is more of a firm number that we have in the pipeline. The pipeline is actually capable of more capacity. We also have planned compression in the next six to nine months and then again maybe in 18 months, so there's a couple of moving pieces out there depending on how the program works.

Okay, very helpful, thank you.

Thanks, Jeff.

Your next question comes from the line of Brian Singer with Goldman Sachs.

Hi, Brian.

Hi, good morning. Can you provide some additional color on the Pennsylvania gathering system, what production you're sizing it for, dealing with the pressure as you move it from the well and into larger trunk lines and then what are the key milestones to insure that your 2009 program can get to market?

Okay. Brian, up in our area, we drilled our initial well up there less than a mile from an interstate line. We have secured the agreement for a tap into that line. We have our permits to come off of that interstate line which is, what size is that? And that line is a 36 inch, and we have a 10 inch line that is coming off of that 36 inch that the we permitted. As I mentioned we're clearing right-of-way right now. We're heading North with that line into and up to where we have drilled our second vertical well, it was drilled about four miles North of our first well and we have some, let me just call them additional lines spurring off of that line to go to locations. That is what we're calling our first phase effort and that first phase effort, we plan on having a lot of that completed by August 1. So our initial gas, we anticipate to go in line and start flowing is August 1. Now, for our 2009 program, we have designed an additional 56 miles of pipe. We are extending this system into our lease hold position up there, and we have efforts ongoing right now to get that infrastructure in place to address our 2009 program. And the capacity, I might mention also we have compression we've already acquired and we are addressing those type of infrastructure issues as we speak also.

Can you be more specific on what the volumes are that you think that gathering system will be prepared to take?

Well, initially, certainly 10 inch line is dependent upon the pressures in compression and those type of things that affect it, but 10 to 20 million a day initially is certainly a safe number.

Okay. And I guess to put the Marcellus into larger context, when you think about your drilling program combined with trying to get the infrastructure in place between what you're doing in West Virginia and what you're doing in Pennsylvania, what are your expectations for what that could add based on the number of wells you expect to drill and complete in 2009?

Brian? I'm going to ask for a little bit more time to give you color on that number, and it's simply because we're still gathering a great deal of information up there as we mentioned we're encouraged with what we're seeing. We're not putting everything out in the particular area we talked about in Pennsylvania. You're not seeing information coming out in the area that we drilled our well. That was only the sixth well ever drilled in this particular area of Pennsylvania. Information we have is we still feel as privileged at least with the majority of companies that are operating out there and we're not talking about the details, but we're encouraged, we're expanding the program, we're reallocating our efforts because this Marcellus is going to be an opportunity to accelerate anything we've seen in the East and Brian, if you don't mind, let me take a moment and just expand.

The program has seen us moving and it's kind of of a dynamic decision process for us right now on where we can go, what information we can gather, where we're allocating people, how we're gathering rigs and looking at the necessary equipment to expand this program. The East is seen as you might be aware, the East is seeing an expansion of its entire basin, something like it's never seen before. You've seen some things in some trend areas like the Trent Black River that had pressure environment that the East experienced but from a geographic area, the Trent Black River is a very very small footprint compared to what the Marcellus will bring. We're having to look at now drilling wells instead of drilling on air, drilling with mud. If we need to we're looking at different tests and frac techniques, we're looking at having to bring in higher pressure frac equipment through the basin which they haven't seen before. We're looking at different levels of expertise that the regional employees not just Cabot, but all of the companies that have operated up there are seeing new technology, we're evaluating now methodology in frac techniques to stimulate this Marcellus. With all of this coordination going on, there's logistic issues that we're facing. We're facing also regulatory permitting educational process to areas of of Pennsylvania which as I mentioned the six well drills in the count the it we're drilling in, the local permitting people are new to some of this. You're talking about not just a vertical well program but you're talking about a horizontal well program which affects the permitting process. It affects how you put together the drilling units up there and the land owner issues on educating them as we go is a new process, so in looking at what we're doing in the Marcellus, looking at how Cabot Oil & Gas Corporation program in the East is changing up there is not going to be a quarter to quarter evaluation and looking at it as seeing us be able to just jump right in and know exactly how much the change is going to be.

What we do know and what I think is safe to say right now is that our program is going to go up and to the right at some point in time and coordinating this effort is going to be an ongoing updating process, but it is a new entirely new process in this large large basin area for all of the companies working up there and I think you can tell by the acreage cost up there at the level of excitement you're hearing from different companies that this is a great new opportunity and for a company Cabot's size with our acreage position compared to the other to the other companies from a opportunity to move the needle, we have an excellent excellent position and a footprint up there that's going to make a difference in our future.

I really appreciate that. I guess given the constraints that you highlighted, what is your level of confidence that you'll be able to get down and online 70 to 100 million or sorry, 70 to 100 Pennsylvania wells next year?

Well, we're confident at this stage to be able to do that , Brian. Another initiative that we have ongoing to give us additional confidence to be able to do this is that we have our own drilling rigs now that are capable that we've committed to that we're able to handle. We have secured equipment that will allow us to build locations. We have build with our own equipment and new location, our first new location up there, we're certainly going to continue to rely on and depend on our normal vendors, but we are also to accelerate the program knowing we're going to have to push and to control our own destiny, we have to have our own people and own equipment out there also. So that is some of what we're doing to be able to mitigate the risk of program execution for 70 to 100 wells in 2009. Those were some of the steps we're

Thank you.

Yes.

Your next question comes from the line of Larry Busnardo with Tristone Capital.

Hi, good morning. Just a question in regards to the Marcellus. Can you give us an update as to where your acreage position currently stands?

No, we're North of 100,000 acres in Pennsylvania and that's as far as we're going to go with it right now, Larry. As I mentioned, we have eight in the Marcellus area that we're focused on. We have outside of our legacy area, we have 90 brokers in the field. We have some abstractor on top of that and we're continuing our leasing program.

In terms of the wells that you've drilled today, have they all been concentrated in one area or how have they been distance apart and where is the horizontal relative to where the vertical wells have been drilled?

Yes, in northern West Virginia, we've drilled a couple of Marcellus wells. Those two wells were 20 plus miles apart, and in Pennsylvania, all of those wells are several miles apart but within our acreage block, a large acreage block up there in this particular area in fact we have over a 100,000 acres in this particular acreage block in Pennsylvania and all four vertical wells in the current horizontal well is that's currently drilling is all on this 100,000 acre block within one area, and in fact the horizontal well is being drilled from the same pad as one of our vertical wells.

Okay. I guess shifting over to the Moxa Arch, you talked about potential horizontal activity there this year. Has there been any I guess plans on that or can you give us any update on that program?

Yes, Larry. I'm going to let Mike kind of update us on that.

Yes, Larry, just two things that we're looking at. We mentioned the 40 acre down spacing program on the Moxa for the Frontier. Our engineering is demonstrating that it appears that the current 80 acre spacing is not effectively trading all of Frontier and we're going to try the 40 acres. If that works, that will really increase our drilling potential location on the Moxa. There's also an area in the Frontier in our acreage and northern Moxa that is obviously gas charged. We've drilled a number of vertical wells in the area. It's a thick Frontier section. The wells aren't as good as we would like to see, and we are starting the engineering work right now to test the feasibility of a horizontal well in the Frontier to see how it would work. If that horizontal effort is successful, it could set up very large block of Cabot acreage for potential development in the future. But that's a whole new initiative that we've just initiated within the last few months.

Okay, no plans to actually drill yet?

Actually, I think that if we could get to the point from the engineering side that our guys feel confident in doing that and we can use one of our rigs on the Moxa, I think that we could maybe get one done. If we can get a permit later on this year.

Okay. Just in regards to other activity in the Rockies, are you looking at any other shale opportunities within the Rockies within your existing acreage position?

Yes.

Okay. Don't want to be more specific?

Larry, not at this time. It would be too early.

All right and then just one last one. With all of the I guess the acceleration of the program, did I understand you correctly there's no change to the budget at this point? It's just dollars being shifted around?

Yes. We have our hands full with $560 million, as you've heard us kind of shuffling the deck a little bit and with our dynamic process in the Marcellus and us recently kind of getting the West going and getting the rigs moving in that direction and making sure we can secure all of the necessary support services to get that going, we're not talking about any additional capital at this time, but we certainly are as I mentioned would like to see us up to maybe 25 rigs but we're going to do that in an orderly fashion.

Okay. Great. Thanks for the update.

Your next question comes from the line of Joe Alman with JP Morgan.

Hi, again. On the Marcellus shale, I think in your prior operations update you talked about your first two vertical wells with IP s of 0.8 and 1 million cubic feet per day. Could you give us an update on how those wells are performing now?

Well, Joe, that is in that 100,000 acre block that I've talked about in Pennsylvania, where that one of those wells that I mentioned that you just mentioned was about a mile from that interstate pipeline and the other was about four miles away from that particular well. Those are the two wells that you're referring to, and that is the area that we are going to hot tap into this 36 inch interstate line and lay up into our 100,000 acre block. The permitting process, we have now secured approval for that and we're cutting right away right now to lay up into this acreage block to start hooking up the wells that we're drilling now in this area. Neither of those wells have started production yet because we're getting the pipeline hooked up.

Got you, okay,very helpful and moving on to the Hainesville, I think in your update you indicated 11 vertical IPs ranging from .65 to 2.3 million a day. Those IP rates you gave, what are those? Are those 24 hour rates or tell us the timing of that, what are the results after the IP's and I'm assuming those are all tied into a sales line.

Yes. They are. The IP is your typical four point test that we file and flowing into the line right now is exactly what we're doing.

And also, Joe, these wells are also co-mingled with the Cotton Valley up in the Minden area and they are added to our reserves we're finding in the Cotton Valley.

Got you. So these rates the 0.65 to 2.3, but those are the Hainesville alone; is that right?

That is the Hainesville alone, and as we said in the press release, incremental cost, about 400,000 to $600,000 to drill down and see the Hainesville and we're seeing reserves add up to 1.5 B's for that incremental section. So we feel very very pleased that we're able to get our typical Cotton Valley, Travis Peak reserves in these wells plus we're finding a number of really attractive Hainesville targets.

Got you and so again, so the timing of the IP, Dan, what do you mean by a four point test?

Well, after we frac the well and clean it up, we have to run a test for the State and so we run those tests and get a rate that is based on different choke sizes and then that's the rate that we report.

Okay, so over what time period does that happen?

That just happens over a day or so. We just change choke sizes.

Got you. And so are you saying that these rates are pretty much the rates flowing to the sales line now are pretty much close to the IP rates?

Actually, on several of these wells, the rates have kept up a lot better than expected.

Got you. Okay, that's helpful and then at Trawick, what's the cost of that one well, two point something million a day well.

I'm sorry the cost of that well?

What's the cost of that one vertical well that IP'd at 2.9 million a day.

Of course in the Trawick, we are drilling through a lot of the depleted reservoirs of shallow so we have to drill a larger hole so we are setting more pipe in the hole before we get down to the Hainesville. Generally though speaking depending on how many fracs we put on these wells, 3 million to 3.4 or 3.5 million.

Okay. That's great. And then --

Yes, and Joe, we also in those well bores have Cotton Valley behind pipe that we haven't yet opened up.

Got you. And then Mike, what are you seeing days, what's the current trend for drilling and completion costs? Some Operators are seeing a leveling off of not just rig rates but other services too. A few folks have said rates or costs are going higher, some folks are saying costs are still declining.

Well, some of the rigs that we have, we've had on contract so we've been able to, it's kind of a steady State on rigs. We've seen on the completion side, we have seen moderation in the stimulation side of the business and kind of stayed relatively flat overall. Steel costs are going up. Tubulars is an area that costs are going to rise.

Okay. And then Dan, in terms of back to the Marcellus question, of all of the potential constraints you might have, what do you think would be the biggest drag for developing that program as quickly as you hope to?

Well, I think we have in our initial area up there, Joe, I think we have addressed the bottlenecks that we would see there. We think we're going to have the equipment. We're scheduling up to seven rigs in this particular area for our 2009 program. The infrastructure we're moving forward with there. The pressure testing equipment and stimulation equipment we're securing for an expanded program. If you move again from this area though, I think you could have as each companies programs ramp up, you could have some growing pains into new areas just because the amount of equipment and services available to continue to expand in a new area, that could be a bottleneck down the road, but we feel very good about this initial area where we have a 100,000 acres.

Got you. And then lastly, on your current production, is there anything, do you have any meaningful volumes that are being held back at this point, especially when I look at the County Line wells, those are big wells, and are there any, I know you described how you're completing those wells, but is there meaningful volumes now being held back?

I wouldn't say there's any meaningful volumes being held back right now. we're doing what we can to expedite and get product in line.

Okay. And could you describe the declines of those wells? Because those are coming on pretty big, and I imagine they're declining pretty fast too.

Well, yes. It's not unlike every, well this is actually not like a tight sand but the decline curves are going to be somewhat similar but to give you two points, we've given you IP's and I'll give you a 30 day average and that 30 day average for our most recent wells, actually has been North of 6 million cubic foot a day for a 30 day average, so there's a couple of points to be able to fit your curve.

I appreciate it. Thanks for your help.

Okay.

Your next question comes from the line of Omar Jama with Owl Creek.

Hi, guys. Dan, You use the term " Dynamic" somewhere along the line there and I was hoping you could just step back and give us your perspective on really the question, has there ever been a time where things were changing so quickly in the industry from your perspective? And then second can can you give us some perspective on what Cabot's philosophy is in allocating capital for exploration versus development? So really two questions, just your general perspective and also , what your thought process is going to be going forward on exploration versus

Yes. As far as the dynamics in our industry, Omar, we just had our Board meetings the last couple of days and certainly had a lot of open discussion and looking at the level of activity in our industry, and every other month it seems like there is a new play concept or a new idea or new geographic area that has the opportunity to yield returns that are going to be competitive. The lease activity that is going on and the land grab, if you will, that we're seeing out there is basically unprecedented. We've had now with a five year strip price of 9.50 plus or minus and looking at what is, what we're able to do in that particular area to lock in some prices or what companies can can do and the under pinning of the gas price, there is a lot of optimism out there. There's a lot of geographic areas that historically have not looked at as being able to yield returns that now can yield returns. Technology has certainly enhanced those areas and tight unconventional areas so in my career, I can't think of a time I've seen a more aggressive period where there is such a large large land grab going on in a lot of different areas. I think it's safe to say that's kind of unprecedented and dynamic.

In the East, as an example, the dynamics I referred to is a entirely new idea up there in what has historically been a low pressure operating environment where the equipment was not as beefed up. The fracing technology was not as sophisticated because the need wasn't there. Land costs were not anything big as far as a percentage of your capital in each well, and it was a orderly process. Marcellus and now looking at companies that are and have never been in Appalachia moving up there and making a land grab and trying to get a foothold have really brought to the East East a process that has not been experienced up there. The acreage costs are, can we support the acreage cost? Well, I hope so. But when you look at some of the acreage cost and the areas whereas I've mentioned the sixth well was drilled in a particular county and you're having acreage costs already reach 1500, $2000, on what information is that being built on is, we have information but what information is being built on by others is I think somewhat speculative, though I think from a academic standpoint and what the Marcellus potential is, there might be some reason, but it is, the East Appalachia area has never seen a change as rapidly as what the Marcellus is bringing to this large 500 square mile area, that's transitioning in the East and how we allocate capital is in transition because keep in mind, 40% of our capital, Cabot's capital was allocated and directed to the East. So you look at what we're doing up there right now and trying to transition and run as hard as we can to evaluate the Marcellus in all of the areas we have exposure and acreage and to see what we're going to be able to do on getting our arms around the Marcellus with people, with technology, with equipment, it is dynamic and we are going, you're going to continue to see us kind of move, some moving parts to our capital allocation up there, but we're trying to see with that capital allocation an area where we're going to continue to put the reserves on the books. Those reserves I think will come on the books still in the $ 2 cost to find level. I still anticipate we will organically replace over 300% of our production in 2008 and we're going to continue to grow at double-digit production rates. And I think our return for the dollar invested is going to continue to be enhanced, particularly with the returns we see that the Marcellus might yield over and above our traditional program.

Okay. So like specifically, you guys had started to develop the Hurricane discovery and I'm curious, do you literally take those people and move them over to a whole different area?

Yes. That's in fact what we are doing right now because we're not , we'll drill five of the 19 wells we had scheduled in Hurricane but instead of moving another rig in there, we had planned, we de sided to move that rig on to the Marcellus activity and so we are pushing that activity right now to expedite

Okay, so really, you guys are still in the exploratory phase, it seems like. Rather than the development phase where we would look for rapid production growth.

We are still in a exportation stage of determining where we want to allocate the capital in the different areas of where we have Marcellus exposure plus the new areas we have. That's correct.

Okay, thank you very much.

You bet.

Your next question comes from the line of Jack Aydin with KeyBanc Capital Markets.

Hi, guys.

Hi, Jack.

A couple of questions. First of all, this is maybe different type of question. Now, Mike, we've been hearing a lot about the thickness of shales doesn't matter. The sooner maybe is better. Could you comment a little bit on what you think the nice way to look at it?

Are you talking about the Marcellus shale, Jack?

Yes, about the Marcellus, shale, sorry.

Well, there isn't a lot of data out there. People are talking a lot about what they're doing, but it stands to reason that the thicker the shale, maybe the better the return may be since you are exposing more of the well bore to a thick shale. Of course, if you go horizontal, I think that you should just get as some of the numbers that we've seen, you should see better returns. A thinner Marcellus, I think that we're not drilling really thick Marcellus in Southern West Virginia but we're certainly seeing some good results off of those Marcellus whales down there and I'm hopeful that going horizontal in those wells down there are going to give us even better rates than what we're seeing on the vertical standpoint.

And then in your presentation, you had a gross acres of 1.12 million acres in the East. If you break it down, a little bit more than just the gross, could you just, what percentage of that is a prospective for the Marcellus?

Jack, I would say 30 to 40% of that is prospect us for the Marcellus.

Okay. And again, the last time you had the presentation, you had six areas that the you're leasing and everything and now did I hear you correct? Now you have eight areas?

Yes.

So I assume the acreage in Pennsylvania has gone higher or North of of 100,000?

The acreage in Pennsylvania is going to go higher, Jack, and has gone a little bit higher. We're just, like I said, we have 90 brokers. In the field leasing, and if they aren't picking up leases, then we're going to talk to our East region and ask why.

Okay. The final question, in the County Line, if those wells are coming at those IP rates and after 30 days still running about 5 to6 million a day, wouldn't you think production should come in a little higher than what we have seen?

Well, what we've just now done recently, Jack, is to get our third well out there in the field, and we're, we would expect that our production will ramp up and our field plot, plotting the amount of production versus what number of well s with the decline curves that we're seeing out there has a steady increase in the production profile in County Line, so with three rigs just now kind of out there in the field, we would expect to see production growth continued production growth in County Line and maybe at a more accelerated rate.

Okay. Again, I'm looking at your presentation, final question, I promise. You had the traditional wells about 158, Marcellus about 94, and you said now Huron about 9 and now it's five. Could you give us new numbers for those areas?

New numbers in the Marcellus?

No, just in the East region.

Yes, just a minute, Jack.

The well count, Jack?

Yes. I could call you on the outside line later. You don't have to worry about it.

It's going to be over 250 wells.

Yes.

Okay.

Jack I'm sorry. I will call you back later with that number.

Okay, thanks a lot.

Sorry, Jack. 250 wells. The traditional, Jack, the Marcellus like 77 tails in the South, those are just going to be deepening the traditional wells in Southern West Virginia and those would also include a few wells, four wells up in that central part of West Virginia, and then of course the 30 wells in the Marcellus up in Pennsylvania. It's 30 wells, Jack.

Okay, thank you.

Your next question comes from the line of Andrew Coleman with UBS.

Hi, good morning, everyone.

Hi, Andrew.

I had a couple quick generic questions here. When I think about the Hainesville versus Bosier, I know they're geologically similar, but how do you guys kind of see the difference kind of breaking out because what I heard was that the Bosier was kind of or Hainesville was a little more the same to the Louisiana side.

Well, the Bosier is a shale, a thick shale and it over lies what they call the Hainesville limestone. I think when people say Hainesville, sometimes they're a little confused with what was reported by something called the Hainesville shale, but we are looking at the wells that we're drilling in is the Hainesville carboning . The Hainesville shale, we think, is part of the Bosier shale and it lies on top of the Hainesville. So, when Cabot talks about Hainesville, we're talking about the carbonate unit in the Minden area right

Okay, and is that analagous to like the Trenton line then?

Analagous to the Trenton Line?

Yes.

The stuff in New York State?

Yes, could it be?

Well I guess they're analagous in the sense they're both carbonate, and probably the primary porosity in both zones are enhanced by natural fracturing to some degree, but other than that, they are not the same zone at all.

Fair enough. And what was the total acreage for all of your Marcellus between the low pressure and high pressure, it's close to 300,000, right?

It's actually north of 400,000.

Okay. Perfect, and then I've heard some other operators talking about this pressure rating kind of ranging from 0.4 to 0.7 across the whole play fair way, so if I was to think about lower pressure stuff, I'd try to stick to each bound there, is that fair to look at your acreage that way?

What the we're seeing in West Virginia are rocks that are higher pressure than our traditional sandstone reservoirs down there, and I think if you could, use that lower range number would be an appropriate pressure gradient.

Okay, and is it closer then to 6.7 for the high pressure stuff?

We really haven't talked too much about pressure gradients that we've seen in Pennsylvania.

Okay. But all of those grade gradients because of the depth of the Marcellus would be sufficient to allow you to use the water frac?

That's right. We have used water fracs throughout the Marcellus development so far.

Okay, perfect. And last question, what about exploration expense, was it down in the first quarter relative to the fourth quarter in that guidance is still maintains will trend up a little bit later in the year?

That's right, and we have added on the exploration side the biggest increase is going to be that we have added additional capital for a 3D seismic survey over the County Line project right now.

Okay. Great. Thank you very much.

Okay.

There are no further questions, sir, at this time.

Okay. Appreciate that, Jodie, and I appreciate everybody interest in Cabot. We look forward to giving an update as we get new information. Thank you.

Thank you. This concludes today's Conference Call. You may now disconnect.