Coterra Energy Inc (CTRA) 2009 Q3 法說會逐字稿

Good morning. My name is Cynthia and I'll be your conference Operator today.

At this time I would like to welcome everyone to the Cabot Oil & Gas third quarter 2009 earnings release 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 would now like to turn today's call over to Dan Dinges, Chairman, President, and CEO of Cabot Oil & Gas. Please go ahead, sir.

Thank you, Cynthia, and I appreciate everybody joining us for this third quarter conference call. I have Michael Walen with us and Scott Schroeder, Jeff Hutton, VP of Marketing, and Chuck Smyth, our VP Controller.

The standard forward-looking statements included in our press release do apply to our comments today. As you all are aware, we had issued our press releases last night regarding its quarterly financial results, its operations, and its quarterly dividend, and I'll touch on each of these topics this morning. Financially the Company reported a solid third quarter with $42.6 million of net income or $0.41 per share, after removing the selected items the largest of which was related to stock based compensation. Clearly our hedge position did aid the results with $108 million of increased revenue coming from our counterpart its for the third quarter. This brings the year-to-date hedge gain to $304 million. Also we're about two thirds hedged for the fourth quarter of 2009 at a $10.11 floor.

Additionally, we have six natural gas and one oil contract covering our 2010 production at 1,143 and $125 respect every. For 2010, based on our current mid point of our guidance, we are approximately 18% hedged for 2010. More importantly though, our production once again increased quarter over comparable quarter. For the nine month comparable period, production was up 10%; the largest contributor to this increase was the North Region, specifically in Pennsylvania, which experienced over a 24% growth rate for the third quarter and year-to-date comparison. The South Region was up 11% for the nine month comparison.

With numerous completions on the horizon in both of these regions, we do expect production growth to accelerate in the fourth quarter and to that end, we issued new fourth quarter guidance last night. We raised the equivalent range that was set at $268 million a day to $280 million. We've increased that now as the low end of $280 million and the high end to $295 million per day. We also established our initial level of guidance for 2010 at a range that would result in an overall growth rate of 18% to 23%. The comment I will make in regard to this guidance is that while this level of production growth represents our organic high watermark, we have the rest of the program to account for any uncertainty on timing related issues and bringing things online and the regulatory environment, if in fact we execute the program as we anticipate there should be some up side in the program.

On the regulatory front, we're pleased with the Pennsylvania DEP release of the completion order allowing us to get back to completion. Because of the Greenfield nature of the industry's effort in this portion, that's the northeast portion of Pennsylvania, there will continue to be constant interaction with the Pennsylvania DEP personnel. As mentioned in our press release last night, Cabot revised its investment program for 2009 to $580 million, which has been increased for several Marcellus lease initiatives that we have ongoing at this time.

For 2010, we established our program at a similar rate, $585 million and that is two thirds dedicated to the North Region and one third focused on the South Region. Included in this figure is $34 million for lease acquisition investment and the vast majority of the program is for drilling and completion, which accounts for 75% of the overall total with the infrastructure accounting for another 9% of the total. The Company's balance sheet ended the quarter with debt totaling $810 million, down from the last quarter. If our lease acquisition initiatives are fully successful, this figure could rise slightly by year-end. As for 2010, we're budgeting to spend approximately 105% to110% of our anticipated cash flow and that's using a 550 handle.

First and foremost talking about operations. We have commenced the completion of our first Marcellus well for the fourth quarter with numerous completions scheduled to follow. Secondly, it appears from early indications, which we'll talk in a little bit more detail, we have at our first success with our actually it being our first well, horizontal Haynesville shale well at County Line, and again I'll give some details there, and finally I'm pleased this last week we have moved into our new North Region office which opened in Pittsburgh and now our North team is all under the same roof and I do expect to see improved efficiencies overall from this consolidation.

Moving specifically to the operations, our Marcellus program continues to expand and our 2010 program in the Marcellus will double in size over 2009. We currently have over 170,000 acres under lease in our play and continue to lease, even though lease bonuses have escalated over the last few months, Cabot is still remaining competitive in acquiring leases. Marcellus production continues to ramp up with our results being exceptional. We are currently making north of 50 million per day and anticipate significant growth for the rest of the year. Physical capacity has been expanded to 110 million per day from our Teel Station and we are currently building out the Lathrop Station, which will increase our total combined take away capacity to 275 million cubic foot per day by the end of next summer.

On the drilling side, we've drilled seventeen horizontal Marcellus wells in our 2009 program so far and have an additional sixteen horizontal wells remaining for the rest of the year. With six horizontal rigs, five of those fit for purpose, we are confident that our program will be finished by year-end with some of the completions carrying over into the early part of 2010. At this time we have thirteen horizontals and nine vertical wells in the queue waiting on completion and keep in mind that we have only nine horizontal wells producing at this time, so you can see we've developed a nice backlog. Our plan is to complete at least one horizontal frac well per week for the remainder of the year; however, if we are able to get an additional well or two fracked with an additional crew, we will do so.

The horizontal wells we've completed so far in our program have a thirty day rate averaging 7 million per day. Understandably, we are seeing a slight correlation between the higher rate wells with longer laterals and more frac stages. The last well which had an IP of over 10 million per day was completed with eight stages over a 2500 foot interval. This was only our third well to receive as many as eight effective fracs. With this in mind we will be extending the reach of our laterals maybe as far out as 5,000 feet. It also will shorten up the frac interval spacing to allow us to pump more fracs. We believe this could result in even better results than we've experienced to date.

The bottom line during 2009, our Greenfield Marcellus play has been a Research and Development process. We've tested ideas, working to understand the spacing, optional frac intervals and many other things. We will continue our evaluation process, however, we have certainly enough data collected at this stage to be more aggressive in developing the play with horizontal wells and that is now why we are doubling the activity in 2010 over 2009.

Also, I need to make a brief comment regarding our operating practices and our expectations as we continue to develop the Marcellus. It has always been Cabot's policy to operate prudently within the rules and regulations of our operating areas to insure the safety of our employees and protect the environment. Cabot has been operating in the Appalachia area for over 100 years with these guiding principles. Through the years, we have had some operational upsets; however, we have always taken appropriate corrective action to mitigate further problems. We have worked cooperatively with the Pennsylvania DEP to enhance operational practices, allowing us to continue to develop the natural gas from the Marcellus formation. Natural gas is the cleanest most abundant energy source this country has and Cabot will continue to provide this valuable product to the nation with the respect and compliance of all rules and regulations designed to protect the environment. With the heightened focus on gas operations by the public and in Washington, it is incumbent upon operators and its service providers to continue to operate prudently.

Moving to the South Region, now let me move where we are focusing on several horizontal plays, a traditional line horizontal, our horizontal Pettet oil play, which we made a release on last night, horizontal Cotton Valley Taylor, Sand, and I'm sure you'd all like to hear about our first horizontal Haynesville shale well. As you read in the release last night, Cabot and our partners have successfully completed our first horizontal Haynesville shale well. We have a 42% working interest in this well. This well was drilled to a total depth of 17,000 feet with a 3,400-foot lateral and was completed with a 14 stage frac. After 11 days flow back period in the shale, the well is making approximately 21 million cubic foot per day. We think the well could improve slightly as it continues to clean up.

Obviously we're excited about our first horizontal well. This was a great first start since we drilled, the vertical Number 3 last year in our County Line acreage, we had exceptional flow rates from the Haynesville shale, and we always thought there was a high potential for horizontal Haynesville shale well in this area. These results coupled with the success of other wells, offsetting Cabot acreage, suggests the high rate Haynesville shale play certainly extends into this part of Texas. Cabot controls 61,000 gross acres, 32,000 net acres over the Haynesville shale area. We think we have anywhere between 150 to 250 gross locations on this acreage with under-risk resource potential between 750 Bcf to a TCF plus.

Our second AMI test well is currently flowing back. It is too early to report the results of this well. We will report the results as more information becomes available which shouldn't be in the too distant future. Our third AMI well for the horizontal Haynesville shale will be spud in early December and the fourth is scheduled for early 2010. We will monitor our discovery and plan our next actions accordingly, however, we are moving ahead and preparing a nearby 100% Cabot operated location for an early 2010 spud. Our early 2010 plans approved by our Board yesterday include five Haynesville shale wells.

On another front, we have stepped up our activity in our Pettet oil field as indicated in the release last night. I won't rehash the details but we believe it does make a lot of sense to exploit this reservoir due to the broad spread between oil and gas prices. This play needs only a $15 oil price to generate about a 15% after-tax return. We have one additional well completing at this time, and we're drilling our sixth well. Five additional wells were planned between now and the rest of the year. In 2010, we have scheduled eleven Pettet wells to be drilled.

2009 certainly will be another good year as we get year-end results. We will see a significant production growth for both the Company and for our developing program in the Marcellus. We have significant opportunities in both our focus areas and will exit the year on a strong upward growth curve. Organic drilling replacement, reserve replacement will exceed 200%, even with the sale of our Canadian assets, with this success we're seeing in the Marcellus and now the new Haynesville success, we could add maybe even higher reserve replacement than the 200%.

Recapping our 2010 drilling program, it is focused entirely on the Marcellus and in the East Texas region. Approximately two thirds of our spending will be in the Marcellus where we will plan to drill seventy-three horizontal wells plus ten vertical wells. Concurrently, we will be expanding our pipeline and facilities. In East Texas, our original plan at this stage is to continue to drill Pettet, James Taylor horizontals plus a few additional Haynesville shale wells, however, with the recent positive results from our first horizontal Haynesville shale well, we will probably rethink our capital allocation in this area with an eye towards expanding our horizontal, excuse me, our Haynesville exposure.

In summary, we have a positive near term outlook for natural gas and we do certainly plan on enhancing our hedge position. In closing, we have an impactful acreage position, as you are aware, in two prolific plays both in the Marcellus and Haynesville shale. We've confirmed the geology in the area. We've confirmed the operational results that are going to yield significant growth and with a strong balance sheet, Cabot will be able to generate significant growth with our 2010 program.

Cynthia, with those comments I'll be more than happy to answer any questions.

Thank you, Ladies and Gentlemen, (Operator Instructions). Your first question comes from the line of Ellen Hannan with Weeden & Company.

Hi, good morning.

Good morning, Ellen.

Just a couple of questions on your acreage position in Northeast Pennsylvania. You said 170,000-acres, I wanted to see if that was your net number and in terms of leasing are you looking at anything in New York State?

As far as our gross to net up there, they're just about an overlay, Ellen, on the numbers I gave you, and in regard to New York, there is still not any clarity yet on when the Marcellus or other operations will be available in New York and hence we are not spending any capital in looking in New York.

Looking at your efficiency ,again in the Susquehanna area, going from eighty-seven days, it looks like, from drilling completed well down to twenty-two, it looks like the completion part of your activity is actually increased, so what do you attribute that efficiency gain to?

Well, we have on the completion side, of course, the water hauling is a big issue for us. We have acquired and have built more frac tanks to be able to move around to locations so logistically, we're now able to get out ahead of the completion process more so than we were earlier when we had fewer trucks hauling water, fewer fracs and so we're now on a pretty good steady incline and the twenty-two days actually it's kind of been between eighteen to twenty-two days is our drilling only number.

Great. Thank you. I just had one question in your Southern Region. You mentioned I think that you said you're looking at five horizontal Haynesville wells planned for 2010 at this juncture. Are any of those 100% Cabot wells or are those all in your AMI?

Yes. The location we're preparing and starting to prepare right now, which offsets our Von Gets well, is a 100% location at this stage.

That's it for me, thank you.

Okay, thank you.

Your next question comes from the line of Michael Jacobs with Tudor, Pickering, and Holt.

Good morning everyone.

Good morning Michael.

Dan thanks for walking us through your activity by region as it relates to how we should think about guidance. That's really helpful. I had a few follow-ups to that end. I wanted to kick things off in the Marcellus. When we look ahead to 2010 of the seventy-three wells that you plan to drill, how many of those do you expect to put on to sales?

I haven't counted on our sales forecast to generate our guidance, but they're going to be all the way through drilling all the way through the year kind of like we are right now and drilling up through the end of the year and I would say there's probably two thirds is a good number to be able to say that's the number that would be in that sense having first production 2010.

That's helpful. And you talked earlier about having 275 million a day of gathering in hand. Can you walk us through how that builds up as you go through the year?

Okay, because there has been questions in the past on capacity and the infrastructure capacity, along with production, along with transportation, but this is infrastructure capacity and this has to do with the compression installation that we're putting in the Lathrop Station. We have the ability to push through 110 million a day at our current tab at the Teel area.

We're installing compression or building out the pad and the compression site at our Lathrop Station and that, with the amount of horsepower and compression that we're installing at Lathrop, that will allow us to put into that additional tap in that additional area 165 million cubic foot per day for a total of 275, and that will be instantaneously available once we debug the compression and turn it on and certainly, obviously, having the amount of gas to do that.

So that's something you still expect by the First Quarter of 2010?

We expect this is in June plus or minus June is we expect in 2010 to have those facilities fabricated and installed.

And then to your earlier comment, any updates to firm take away and how we should think about selling that whether it's forward haul or backhaul in 2010?

Yes. We are again still moving gas on forward haul. Jeff and his group has done an excellent job on being able to use end-user firm to move our gas. We do also through that effort continue to look at different options to tie up firm in the future. It involves not only the Tennessee line, it involves the Millennium line, it involves a line to the south, the TransCo line to the south, and we are in discussions on a number of fronts in regard to additional firm.

I'm going to sneak in one more and I'll hop back in the queue. When I think about $585 million in spending next year, two thirds of that goes to the Marcellus and 75% is on drilling and completion. My math gets about $3.9 million a well and when I try to reconcile that with long term well cost guidance, where is the extra $500,000 a well going towards? I know you talked about longer laterals and more intervals, but doesn't seem like the entire cost would go towards that so any color on that would be helpful and then I'll hop back in the queue.

Yes, Michael, as I mentioned, we have gone out anywhere from say 1,200, a little over 2,500 feet laterals, where we can, and a higher percentage of the wells in 2010 are going to be longer laterals and we do anticipate getting a higher percentage of our wells with eight frac stages or greater, which will add a little bit to the cost and we think will enhance the results.

Thank you.

Your next question comes from the line of Joe Allman with JPMorgan.

Thank you, good morning everybody.

Hi, Joe.

Dan, you might have said this, and I apologize for asking again, but could you just go over the cost per well, the latest thing that the horizontal Haynesville well, the Pettet oil and the Marcellus Shale, what are the recent costs and what are the target costs on a longer term basis?

Okay, on the Haynesville well, we were about $10 million with that fourteen stage frac. On the Marcellus wells, we are right now $3.6 million, with those completions completed well cost; on the Pettet, we are about $3.2 million on a completed well cost. And then on this one?

No, just in terms of target going forward what do you think, I know of course if you had more lateral and more stages, do you think costs will go up or they will go up short-term, but then come back to the current level and potentially go lower?

Well, I think the costs are in the ballpark of kind of where we have forecast, as I mentioned just a little bit ago, we are going to be getting and drilling a little bit longer laterals and we are going to maybe space our fracs a little closer together in the Marcellus and hence we think we're going to be able to add additional fracs to each well.

With that being said, the cost depending on the number of fracs could go up a little bit, but overall, I think the ranges that I gave in cost is a good illustration and for modeling purpose would be good numbers to use for 2010.

Okay, that's helpful and then in terms of development of these plays, could you give us what you've budgeted in terms of the rig count for these plays in 2010?

Well, the rig count in 2010 for the Marcellus is going to be the kind of the six wells that we have operating right now, and as I mentioned five of those are fit for purpose. In East Texas, we're going to be working between three and four rigs in our East Texas area.

Okay, and then the Pettet stick with one there?

Well that's in that count of three to four rigs.

Got it, okay, thank you very much.

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

Thank you. Good morning.

Hi, Brian.

As you go back to the Marcellus wells and the horizontals that you've completed over the last ten months or so, can you just talk to how those wells are declining relative to your expectations?

Well, we have nine of them in production, three of those have produced over a Bcf. Those wells have exceeded our expectation; we have a shallower decline than we had originally modeled, so we've been pleased with what we're seeing.

Is it enough where you would change the type curve or can you talk more specifically or is it just something that you're monitoring as you go forward?

Well it's still a very small sample pool. We're confident with the results and the geology, but it's nine wells with the amount of term we have on producing is a small sample pool, so we are -- it's prudent to be a little bit conservative if you will, but it's still fairly robust numbers when we're using 4.5 to 5 Bcf plus on the EUR expectations of these wells.

Okay, that's helpful. Continuing on the Marcellus, you mentioned no New York activity. What about Southwest PA, or Northern West Virginia? Is there any plans or any updated thoughts there?

Well in Southwest PA, we don't have a big push in Southwest of PA; we do have some acreage in Northern West Virginia that we've had as part of our legacy assets, and we have not moved towards developing that down there. We're focused purely right now on our Pennsylvania; Northeast Pennsylvania operation.

Once we get our full compliment of people in our Pennsylvania office, which we again just opened this last week and we let everybody kind of let the dust settle to get out of boxes and refocus the effort, it's certainly going to be in Northeast PA initially but I'm sure through the middle of 2010, Mike is going to have these guys looking in other areas also once we get our Northeast program lined up.

Great. Thanks and lastly on the Haynesville, as you're completing or testing the second well and then as you look to drill your 100% well, any changes in how you're thinking about the completion of the frac, will it be similar fourteen stages or anything that's really different from the well that you just did?

No. Right now, we think the lateral length, we think the number of stages and the spacing is good. Certainly has yielded good results so far. We see no reason at this stage to amend the recipe.

Great. Thank you.

Your next question comes from the line of Robert Christensen with Buckingham Research.

Yes, on the Von Gets well, you said it had a substantial flow rate. Could you refresh my memory as to what that vertical well.

Because it was very early in the stage of drilling the Haynesville shale down in that particular area, we never made a release of that and we didn't test it that long, but it was certainly a couple of million plus a day out of the Haynesville shale.

And then on the second well that's slowed testing what is your working interest on that one?

The second well?

Yes.

The second well at the AMI is where we have retained a override in that particular well. It is a well that we wanted to gather some significant data and still be able to participate, but we elected to retain an override in that well.

Same on the third well and fourth well?

Third well, we'll have a 29% working interest, and the fourth well, we'll have a 22% working interest.

Okay, very good. Thank you.

Your next question comes from the line of Joe Magner with Macquarie.

Good morning, thank you. In the Marcellus, you mentioned you've got over 170,000-acres now. What is your plan to add additional acreage up there?

Our plan is to continue with our brokerage land department effort to cobble together acreage where we think it's going to be beneficial to our future program.

Any thoughts on how much it could increase that position or will you take it as it comes?

Yeah, we have enhanced our leasehold acquisition budget in anticipation of being able to secure additional acreage, but it is a competitive environment up there and I can't assure you we'll spend those dollars at this stage. That's kind of the reason we couched it in the way we did.

Can you provide any color on what leasing rates are right now?

No.

Okay. And then I missed this but when was the initial Haynesville shale well located?

The initial Haynesville shale is in our County Line acreage. We contributed some of our County Line acreage to this unit, so it's in and on the southwest portion of the County Line acreage.

Okay, and then just one last quick one. You were at one point waiting or results from a Haynesville lime well. Do you have those and can you share any additional thoughts on plans to cast other horizons such as the Bossier shale well in East Texas? Thanks.

Okay, thanks, Joe. A couple things, one on the horizontal Haynesville lime well, with the positive results we had with our horizontal Taylor Sand well and that well came on at 9.5 million a day, that well is still producing about over 5 million cubic foot a day and it's held up very well.

We are currently drilling, instead of the horizontal lime well, we're drilling our second horizontal Taylor Sand well, as we speak, and so we feel comfortable about that; and the other question was in the Bossier, in the Von Gets, we drilled, again, our vertical well in the southern portion of County Line. We drilled and tested the Haynesville lime, the Haynesville shale, and the Bossier shale in that well each zone tested gas, and we will continue to evaluate the merits of putting a well into the Bossier in that particular area.

Your next question comes from the line of Ray Deacon with Pritchard.

Hi, Dan. I was wondering if you had any thoughts on the EUR of the Marcellus wells; how do they look versus the type curves that you seen out there.

Well, the curves that we've seen out there, we think they're very good curves. We liked each of the curves that we've seen in the Marcellus and we very much like the curve fits that we're placing on the Marcellus right now. The curve fits that we have again are just -- to range it out and not be specific at this time because we only have a sample pool of nine wells so we're not, we want a larger sample pool before we roll ours out but we think that curve fit is going to be 4.5 to 5 Bcf plus is going to be the curve fit of our horizontal wells.

Got it. Thanks very much.

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

Hi folks.

Hi, Andrew.

Got a question on the capacity going to 110 million, going to 275 million by the summer, 2010; how much of that is going to be firm?

Well, we're working on that. As of now, we have 70 million cubic foot firm on the backhaul and then -- no, actually in August it went to 70 -- and then it increased that to 100 by almost contemporaneous with the time that we bring on the Lathrop Station, and as I mentioned, Andrew, Jeff and his group are continuing to work with a number of parties to secure additional firm transportation.

Okay, and then second of all looking at the CapEx program for 2010, to me it looks like to stay within the cash flow that you'd imply something like a $5.50 gas price for next year in the forecast. Is that a fair assessment or can you tell me what prices you're using?

So that's exactly right, Andrew.

Okay, great. And then the last question, I thought I heard you mention something like that reserve replacement for the year. Can you give any color on that or did I miss hear the 200% number?

No, what we're saying is just with our drill ads right now it's looking like towards the end of the year or at the end of the year that we will exceed 200% reserve replacement is where we are right now.

Do you see much of a change in PUDS that you might book from this or do you think you'll be pretty well consistent with last year and other bookings?

I think we'll manage the PUDS similar as we have in the past. There is the SEC regulations that is out there that all industry is dealing with right now, and we're all sorting through exactly the impact on our PUD booking in 2P, 3P opportunities, but I think it's safe to say Andrew that we're going to remain fairly conservative in the way we recognize PUDs.

Okay, so then based on the math I've got here it looks like something close to similar to F& D costs last year in the $2 range and it looks like a pretty good result there, so thanks again that that was very nice guidance there.

Thanks, Andrew.

Your next question comes from the line of Krystal Choy with Raymond James.

Thank you. Most of my questions have been answered. I had two really quick ones on the Pettet. I was wondering how you've been choosing your locations and how much risking do you have factored into the 175 to 225. I'm trying to see if there's upside to that number.

Crystal, I'll let Mike answer that.

Crystal, we have completed our 3D program over our majority of our County Line acreage and now we are utilizing that data to pick the best locations that we think that we have. Obviously, we are drilling some wells to hold acreage. We have units that need to be HBP'd and, of course, that drives to some degree our location.

Okay, and the first sustainable forest well, can you tell us what that's producing right now?

The one sustainable forest well in the first one, what's it produced at today?

Yes.

Man, I'm going to say 200-barrels a day plus, plus gas. I think that well came on for eight hundred or nine hundred barrels a day IP, I believe.

Okay, thanks.

Thank you.

Your next question comes from the line of Michael Jacobs with tied or Pickering Holt.

Hi, gentlemen. Dan, I'm majoring on the minor here, but just a little bit more color on production guidance, I hope you can in bulge me. The Marcellus clearly drives growth, when I look at your quarterly production guidance and specifically at the second quarter of 2010, it suggests that you could get gathering in hand sooner than June. Are you being conservative with that guidance of when you expect the additional station to come on?

I'll let Scott answer that.

Mike, one thing that -- I had this question earlier this morning already -- one thing you have to factor in is part of the ramp up in the guidance that you see in the second quarter is right now in the 2010 plan. All of the deferred East Texas wells are planned to be completed in the first quarter, so there's a ramp up in the South Region's production along with the carryover Marcellus completions.

In terms of -- let's clarify this again -- that we have capacity on our system that we're building and we have two compressor stations and that's the 275 number that we should have during the summer. We have the 70 firm take away right now that will go to 100 next summer and separately we're working on over a handful of initiatives to increase that firm take away capacity and stage it in over the next several years, and when you have a high degree of confidence we'll be able to do that based on where we're at so we don't have the concern. If we had a large amount of concern that we wouldn't be able to take the production off of our acreage, that risk factor would have also been reflected in the guidance we put out for 2010.

That's perfect. And you talked about the several initiatives to boost overall firmness, if all your initiatives are successful what could the total firm in hand be at some point in the future in a couple years out?

Let's just say it would exceed that 275 number.

That's great. Thank you very much.

Thank you.

Your next question comes from the line of Biju Perincheril with Jeffries.

Good morning. Congratulations first of all. Question on the Marcellus completion. Obviously, you're forecasting a pretty nice step up in activities from what we have seen so far. Can you give us some more color on that as far as what's driving that? Is it having the backlog of wells that are tomb encased? Is it personnel or give us more additional color on what's driving the increased activity there.

As far as the number of completions between now and the end of the year?

Right. It's a nice step up from what we seen so far in the completion pace.

Well it is and it's just kind of the maturing of the Greenfield operation. We have consolidated a whole lot of equipment and got more equipment up there. We have our, as I mentioned, our frac tanks, more frac tanks. We have continuously and will continue to hire additional personnel out there in the field and we're just getting a little bit ahead of the game. Mike I'll let you expand on that.

Two things, Biju, that I'll add to Dan's comments. Number one, remember we talked earlier about having multiple wells being drilled on pads and now we're able to move some of those rigs off those pads and we have multiple wells per pad to complete going forward, and the second item is that we're making good progress on gaining our pipeline permits and being able to lay pipe into new areas, which are allowing us to complete wells. Before we didn't have a permit, and there for we couldn't slow the gap, but now we've overcome that bottleneck.

So for next year's program for the gap in lines, you have those permits in hand now?

In the area where, yes, in the major area to the north and west of our core, we have those permits in hand, and we are working through the permit process for expanding pipeline in 2011 and 2012.

Perfect, that's helpful, thank you.

Thank you.

Your next question comes from the line of Patrick Walseth with Stifel Nicolaus.

Thanks for taking my question. In the Marcellus, when you look at the 2010 budget and you start to think about all the activity that's taking place, both in the Northeast and more so in the Southwest, but Pennsylvania that is, do you start to look at completion costs and service costs, really, seeing increased pressure to increase or is that something that possibly takes place later on in maybe 2011 or later there?

Well, any time you're going to see a region that has a ramp up of activity, there's going to be certainly a little bit of pressure on service cost. I will say this, though, that as you do see more activity and there's more commitments by operators up in that particular area, the service companies have a significant amount of idle equipment that they are going to be moving up to the East also, so it certainly is a little bit of a risk any time you have an uptick of activity, but the service companies want to utilize all idle equipment and this is one of the areas they will move to. All of them are talking about opening up offices or have recently opened new offices up in Northeast Pennsylvania or New York.

Perfect. Thanks. That's all I had.

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

Hi guys, congratulations.

Thanks, Jack.

Dan, on the DD&A, the guidance is 240 to 260 and you're replacing your higher cost with lower cost. That 240 to 260 is a little bit on the high side, could come down a little more?

Jack, what's also flowing through there is undeveloped acreage amortization.

Oh, okay.

And you know Mike is --

I know. I know. All right, now, in terms of hedging, what level do you think you might start putting some hedges in 2010, 2011?

Well, actually, it ran up in the early part or the end of last week, and we were looking at it and convened our hedge committee and looked at the pricing and got some quotes so that's an area that we would be inclined to start layering in some, and not in a big way, but layering in some. Frankly, we do feel that there's a supply is decreasing and we think certainly there's an opportunity for a little bit more demand use. I know the chemical side seems to be enhancing demand a little bit, but we do feel like that in a $6.00 plus range that we would layer some in.

This is a little bit looking forward. I know we are in 2009 and we are just starting 2010, if you look in 2011, what kind of spending you might be looking and what kinds of drilling growth you might be looking at? I'm not looking for an exact number, just conceptual.

Well, conceptually, I'll just really stay focused on two areas. I'll stay focused on the East Texas area and the Marcellus area, with the amount of acreage we have, with the thousands of locations that we have out in front of us, our strategy to capture our primary term acreage, and that's only done by drilling, I think it is safe to say that we will continue to enhance and increase our drilling program that will allow us to maintain our primary term acreage in the Marcellus, in particular, and I think it's safe to say that with the continued results of high rate Haynesville completions that we will allocate additional capital to those particular type of wells.

So I'm very, I don't have a specific number, but I'm very excited about the two areas that we're allocating capital. The returns that those two areas yield for us and our shareholders and I would expect there to be a significant growth component to Cabot.

Mike, a question about you and I talked about spacing of the Marcellus. Of the seventy-three wells that you are planning to drill in 2010, any of them closer than what you have been doing?

Actually, Jack, we've actually accelerated that initiative and we're going to be drilling some wells in the fourth quarter that are going to be considerably closer than our current spacing. We do not yet have a feel for what the effective spacing on these horizontal wells will be or should be, and we're starting out that down spacing the effort right now.

How about stack laterals? Are you going to experiment on those too?

Yes, yes we are. We're going to investigate the engineering mechanics of doing that and see how that works out. That's a bit more of work needed to be done along that line, but that's something we're going to look into. Again, fourth quarter, '09 and first quarter, 2010.

Well, can't wait to hear. Thank you.

We're also just, as a case in point, along those lines, but it's separate well bores, we are going to do horizontal wells in the upper Marcellus and also in the Purcell to test the frac efficiencies in those intervals. We already know about the two zones, our gaps varying just from our rock work and pass completions in vertical wells and we'll continue and now do the horizontal route and see what happens.

I'll follow on this one. If successful, what kind of potential reserve will we be looking at, doubling, 25% more than what you have been talking about?

The core work that we've done and with the core consortium is done up there in Northeast PA, it's suggests to us that the upper Marcellus for sure will be a significant reserve add. I think the Purcell is still a little bit unknown, but we're very bullish that it will be a significant add to the play, because right now we don't believe that we're getting effective stimulation through the Purcell or the upper Marcellus.

Thank you.

Your next question comes from the line of Joe Allman with JPMorgan.

Thanks again. Just a quick one on the Marcellus Shale. What are you thinking about in terms of recycling water and what would the cost implications be if you increase your recycling of water?

We have actually gone full cycle now with that process and we're trying to expand the size and capacity that we can recycle. We have fracked the well. We have captured all that, actually two wells, we fracked two wells and we've captured all of the produced frac water. We've recycled it and we have now gone back in and used that recycled frac water to refrac another well, so -- and we were effective and successful in doing so, so we will continue to explore and exploit the efficiencies of that practice.

And with the initial thoughts about the cost implications there?

I'm willing to let Mike answer that.

When you consider the trucking costs and disposal of some of these fluids down into a commercial site, it will probably cut our cost by about 50% or more. For just handling the water.

So the cost there is from what to what?

Well, we're looking at range of $10 to $12 a barrel to get the water down to our disposal site and that includes trucking, plus the cost to dispose and by doing the recycling we could cut that by over half.

Okay, very helpful, thank you.

Your next question comes from the line of Robert Christensen with Buckingham Research.

Thank you. I'm just trying to get a sense of how the Haynesville program will develop a little bit geographically from this latest well. The second one you're testing, how far away is that from the one (inaudible).

The second well we're testing is four, maybe five or six miles away from the Von Gets well, and -- but it is around acreage that we own.

And then the third well that's spud, how far away is that from let's say the Von Gets. Let's use that as a marker.

The third well is going to be probably five miles, and they're going to be on the current well we're testing is west of the Von Gets and the two and three well are going to be east of the Von Gets.

That's the third well five miles east and then the fourth well, sorry?

The fourth well is going to be kind of southwest.

Okay, so just trying to get at those four wells would encompass how much acreage in between if I had to--

Just about all of it.

So everything inside we could start to get more comfortable with?

Yes.

Yes. Very good. Thank you.

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

I'll just say I appreciate all of the interest, and certainly the Haynesville is a new wrinkle to the Cabot story with the success we've had, and the Marcellus continues to show very strong results. I think with our stepped up program and acceleration of our activity up there and getting everybody under the same roof, I think you can anticipate that we will have a ramp up of activity that we can report at the end of the next quarter; and again appreciate every body's interest. Thank you.

Ladies and Gentlemen, this concludes today's Cabot Oil & Gas third quarter 2009 earnings release conference call. You may now disconnect.