Coterra Energy Inc (CTRA) 2006 Q4 法說會逐字稿

At this time I would like to welcome everyone to the Cabot Oil & Gas fourth-quarter and year-end 2006 conference call. (OPERATOR INSTRUCTIONS). Thank you. Mr. Dinges, you may begin your conference.

Thanks, Stephanie. Good morning. I appreciate you joining us for this year-end teleconference call. With me today I have several members of our management team, including Mike Walen, our Chief Operating Officer, Scott Schroeder, our CFO, and Jeff Hutton, our VP of Marketing, and Chuck Smyth, our VP, Controller.

Before we start, let me say the standard (indiscernible) forward-looking statements comments, including on the press release, apply to my comments today.

As you read last night, or early this morning, Cabot issued two releases, one with its statistical highlights for the year, and one giving an update on our operations. Both emphasize the significant progress Cabot has made operationally and financially over the recent term. Because I believe Cabot's ability to add to its reserve base in an efficient manner is of a high priority, let me start with discussing reserves.

Cabot reported 1416 Bcfe of total produced reserves, surpassing the 1.4 Tcfe mark for the first time in our history. The 6% increase in reserves came in a year when we sold 68 Bcfe, we removed an additional 18 Bcfe from the tail of our reserve profile as a result of year-end commodity prices, and we produced 88 Bcfe.

Our proved reserve makeup at the end of the year was 50% in the East, 32% in the West, 17% in the Gulf Coast, and 2% in Canada. Additionally, across these regions, Cabot estimates it has over 10,000 locations and over five Tcfe of unrisked resource potential.

Cabot's drilling program has increased about 2.5 times since 2003, with approximately 440 wells scheduled in 2007. This expanded program allows us to slightly increase the PUD component of our reserve profile by 2%, which puts Cabot at 73% proved developed.

In regard to the efficiency of our operation, our goal is to add new reserves for about $2 per Mcfe all-in, and I am pleased to report we were able to achieve this goal despite in spite of the inflationary environment we experienced for 2006. Additions from drilling were $1.97. When you add purchased, which is only 2.2 Bcfe, it was $1.98, and the effect of revisions took the all-in cost to $2.10 per Mcfe.

Cabot, like many of our peers, saw negative revisions due to the reduced year-end gas pricing. Revisions as a result of year-end pricing increased our all-in finding cost approximately $0.15. I firmly believe that when all reports are in for the year, Cabot's 273% reserve replacement, at around $2 all-in, with minimal movement in the PUD percent, will stack up very well in relations to our peers. Another consideration in regard to these achievement levels is the fact that Cabot can duplicate these results organically from its low-risk portfolio.

In regard to production, for the first time in several years production was a highlight for Cabot in 2006. As the release indicated, we experienced an absolute production growth rate of 4.6%. This was with the removal of approximately 36 million cubic feet equivalent per day for the entire fourth quarter due to the sale of our South Louisiana and offshore properties. Had we harvested these assets instead of sold, this growth rate would have been approximately 8.5%. Most importantly, the retained asset comparison in 2005 versus 2006 yields a 17% production growth rate. Because of this growth rate and the progress in our program, our estimate of 12 to 18% growth rate remains our guidance.

Pricing, together with production dynamics, allowed Cabot to post its best financial earnings. Our realizations on both natural gas and oil were slightly above 2005. Cabot's wide collar hedge philosophy was put in place late in 2005; afforded us a revenue pickup in 2006 of $28 million, all from natural gas. The oil hedges remained within the collar range. For 2007, Cabot has about 50% of our anticipated production hedged, with a weighted average floor north of $8 per Mmbtu. No hedges have yet been put in place for 2008; however, we do continue to evaluate the market.

As you read in our release, the Company reported net income of $321.2 million, including a $145 million after-tax gain from the sale of domestic properties. Once you remove that noise, the earnings were 178.5 million, or about 30 million higher than last year's earnings, which was the previous record for Cabot. Expenses grew as expected due to the inflationary pressure in the industry. An unexpected increase occurred in stock compensation expense due to a significant stock price gain that generated over $600 million improvement in market cap for our shareholders.

When you look at Cabot's financial position, we are in the best financial position we've ever had. Our capitalization at sub-20% affords us significant flexibility, which is extremely important in light of our opportunities in our portfolio.

On operations, last night we gave a brief update on the status of a couple of our areas. Let me give some color on those and some other projects.

Our 100% working interest Minden project continues to exceed our expectations. We have drilled and completed over 40 wells to date without a disappointment. Four wells are currently drilling, with eight wells being completed or weighing on pipeline. We currently believe the average well will yield 1.4 to 1.8 Bcfe of reserves in the Cotton Valley, plus an additional Travis Peak reserve potential of 0.5 B to 1 Bcf per well at a completed well cost of $2 million to $2.2 million. At this time we see over 100 Travis Peak locations on our acreage.

As a result of some horizontal success in East Texas, the Cotton Valley horizontal well is planned to spud in March of this year. Also, we just finished drilling our salt water disposal well, which will enhance the economics of our flood. We will pipe our produced water from each well to the disposal facility, which would save us $1.20 per barrel trucking fees off our LOE.

As a result of the drilling and completion of our first two wells in County Line that we previously announced, we're extremely excited about the potential of this prospect. We will start additional development this year with an initial four-well program. At this time we plan to drill two James horizontals and two Pettet horizontals. Spud of the next well should occur in March. Cabot has a 100% working interest in this prospect. This is an area that could see increased drilling over our scheduled program. We're currently participating in a 7000 foot horizontal James test adjacent to our County Line block. So far we're encouraged with this drilling and feel this opportunity will expose the potential for horizontal James in this area. This well should be completed in a couple of weeks.

Moving to the East, our East region horizontal shale program has kicked off earlier than scheduled for 2007, with the drilling of our first well and the spud of our second well. The first horizontal well will be completed in two weeks. Mike mentioned that this last well we drilled was drilled in 15 days with a 2400-foot put lateral for $790,000. At this time we plan a six-stage frac on this well. This will be the first time we have implemented this type of stimulation program. The additional frac job will cost approximately $180,000.

Our 2007 horizontal program is projected to drill between 12 and 15 wells at this time. The majority of these are designed to go horizontal in the Huron section of the Devonian shale. We are very pleased that we can drill and complete wells for about $1 million, and we think we can accomplish this for even less as a result of the drilling of this last well. Our objective, obviously, is to get flow rates at a consistently high rate to meet their economic hurdle. Clearly, however, lower costs reduce the production hurdle to enhance our economics. We will be reporting on this progress on our horizontal program throughout the year.

Our Moxa Arch infill program in the Rocky Mountains continues to yields exciting results. We have drilled or participated in 36 wells during 2006, yielding an all-in finding cost of $1.80 to $1.90 per Mcfe, with a rate of return between 22 to 26% if you use about a $4 Rocky Mountain gas price. We will continue our aggressive program in 2007, as we have scheduled about 30 to 35 operated wells, and anticipate an additional 10 to 15 non-operated wells in the Moxa Arch area. We have two rigs running -- operated rigs running at this time and will keep this level of activity throughout 2007.

In our Nelson Creek prospect -- this is the exploration well we were drilling in the Paradox Basin last year -- we had to delay the completion attempt due to winter rain [stips]. (indiscernible) will start up again this summer, at which time we will be able to evaluate the well.

Moving to Canada, the anticipated pipeline upgrade in the Hinton prospect area has been completed and is now operational. The Hinton project is currently flowing at approximately 20 to 25 million cubic feet equivalent gross per day, and 11 to 14 million cubic feet net per day from two wells. The third well has been completed and will test shortly, with an anticipated tie-in within four weeks. Cabot plans to drill two wells on the structure during the first half of 2007, with the first well to spud in March. Cabot has also purchased and evaluated 24 miles of 3-D seismic over the field, with an indicated -- with our evaluation, we indicate numerous additional drilling locations on this prospect.

In summary, as you can see, we have a lot of opportunities with another year planned for a very large drilling program. Our focus is on program execution and our continuing evaluation of areas in our portfolio not mentioned in our report today. Additionally, our strategic goal is to find a method to accelerate our significant inventory, maintaining, however, our financial discipline.

I appreciate your support today in listening to the call, and I'll look forward to reporting our updates throughout the year. Stephanie, with that, I will turn it over if anybody has any questions.

(OPERATOR INSTRUCTIONS). Brian Singer, Goldman Sachs.

Just wanted to follow up on that first horizontal well on the Devonian shale. Does the $1 million that you talked about in terms of drilling completion cost assume all midstream costs, and what rate would you be looking for to give you some confidence that the well will be commercial?

The $1 million that we anticipate being able to have as a completed well cost up there does include the minimal infrastructure or facility hookup costs. Where we're drilling right now -- and we will be drilling our horizontal wells in several different areas this year. And for example, where we had drilled our -- the last two horizontal wells in '06, we are constructing and installing some large pipelines -- I believe 10-inch, Mike? 10-inch pipelines in that area. And that facility upgrade -- not facility upgrade, but infrastructure upgrade, is going to be about $2 million because it's larger pipe. But once we get that initial cost in, then the $1 million will include all of the hookup fees attached to the additional drilling.

In relations to our rate that we would anticipate to meet our economic hurdle, if we get over 1 million, 1.5 million a day, we certainly are going to be incremental in the expectations over our vertical program.

Great. You mentioned the possibility for lowering the drilling costs further. Was that included in the $1 million, or do you feel like there's more room to reduce drilling days, optimize, etcetera?

With this last drilling and some of the things we're doing up there, Brian, we do think that we could possibly lower our completed well costs less than $1 million.

Ellen Hannan, Bear Stearns.

I apologize if you said this; I may have gotten distracted here on Brian's question. Did you give an expectation of your reserves that you're looking for in the Devonian horizontal play in the East?

No, we have not yet. Our reserves up there, though, are kind of a time rate-type bookings. And if we can get to 1 million to 2 million a day on the rate, I would anticipate that we might book 1 million -- 1 B to 2 Bs per well.

Thank you. Getting -- moving down to the Gulf Coast region, where you plan the horizontal wells in both the Pettet and the James lines, can you give us an idea of what you expect -- your expected well costs, and also what your kind of modeling for an EUR?

We have -- we have drilled in the County Line area one horizontal Pettet well. We drilled that well for $3.3 million completed. And we -- and that well came online at about 3 million per day. And that is an unstimulated rate. We would anticipate the cost of future wells to be in that range. The James is a little bit shallower and might be a little bit less expensive. And right now, we're going to want to -- we want to see a little bit of production rate before we start talking about EURs from these wells.

Moving to Canada, when you talk about having numerous drilling opportunities, can you, again, give us kind of an idea of what your idea of numerous is? Would you be looking at something on the same scale as the size of discovery of what you have there?

In the size of 24 miles of seismic -- square miles of seismic that we have evaluated up there, we see five to 10 additional locations in and around the Hinton area. And the expectation would be that -- and again, I need to quantify this -- with the lack of control, with our wells being the only deep control in this immediate area -- certainly some of this is speculative -- but we would hope, if we can see consistent reservoir quality, to have these wells yield similar results. That's yet to be seen without additional drilling.

But in relation to all of Canada, though, I might add that in our [Narrow Way], in our Bolton, in our [Kiskue] and our Chime area, we have a large number of locations that we've identified in those prospects also that we are going to really have our program focused on fleshing those areas out in the form of a higher drilling -- a higher development component to our drilling program this year versus 2006.

One last question for me. And again, if you gave this, I apologize. On your CapEx for '07, did you give a breakout of how much you expect to spend in the U.S. versus Canada? And if you did, I --

Scott has that information at his fingertips.

Ellen, we are going to spend about $25 million in Canada of the 435. And the 435 is the same number that we gave in October.

(OPERATOR INSTRUCTIONS). Jack Aydin, KeyBanc.

Two or three questions. On this track you mentioned that the -- is the $1 million that (indiscernible) you're talking about -- let me go this way. The [eighth] well that you did cost you about $1 million last year. Did that include the frac cost, or there was no frac cost?

No. The $1 million that we reported as our last year was a completed well cost that included the frac.

So, the 790 does not include the frac yet?

The 790 does not include the frac. However, this well we anticipate a six-stage frac, and we anticipate the completion cost to implement the six-stage frac to be about $180,000.

Is this now -- in terms of the cost, do you feel comfortable that this is the type of cost that you're going to be looking at through 2007?

Yes, we do.

Good. Great.

We're very pleased with what they've been able to do on the drilling side and the frac side. We're interested in seeing what our -- this particular frac program that we're going to implement is going to do.

The next question I have, it is on the Paradox Basin. As you know, there is a lot of chatter, a lot of noise going over there. And only you -- could you shed a little more light where your acreage is versus some other operator acreage that they're getting such good results?

Jack, we have a -- and I'm going to turn over to Mike to just let him give some color on the Paradox also. But we have over 350,000 in acres in the paradox, and it's scattered throughout. And the activity that has occurred up there is -- some of the activity is in and around our acreage. We're not yet able to say that -- well, we haven't evaluated the activity that's been reported with our data, and so we're not going to speculate the extent of what's been recorded by others, how it falls onto our acreage. But certainly we're evaluating it, and some of the exploration drilling we have in the Paradox this year will evaluate the environment that's been reported out there. I'll let Mike give a little color also.

We've looked at that activity in some detail, and we have seen where there's a relatively nice block of Cabot acreage adjacent to some of the most recent activity, which we are looking for potential on. In addition to that, we are looking for this play to maybe extend down farther to the South and East, into the part of the basin where Cabot has a very large (indiscernible) position. And right now we are just still evaluating that potential. But it appears that there really might be some serious growth opportunity there in those sandstones.

How much -- what -- when you say a nice block, what kind -- could you put a number in terms of acreage, what you have there near those discoveries?

It looks -- (indiscernible) acreages adjacent (indiscernible) to one other well, company (indiscernible) well, we're probably looking at maybe approaching (indiscernible) acreage.

Then I have the other question. I know you're not going to answer it, but I'm going to ask it anyway.

I'm not surprised, Jack.

Rumor is that you had a well in the Floyd shale that -- vertical well that you produced about 1 million cubic feet a day. Can you shed light, one way or another if you have acreage there? You haven't said it. And could you a little bit elaborate if -- on it a little bit?

As I mentioned in my summary, that we're going to focus in 2007 on our program execution. And we do have other areas in our portfolio that we're evaluating that we haven't said a whole lot about. We're trying to -- we're trying to get comfortable. As an example, our East horizontal well program. We're trying to get comfortable with how repeatable it is. We're trying to build our database, and we want to feel comfortable before we go out and speculate on what the real -- the depth of potential is.

And yes, we do have acreage in the Floyd. We also, though, in this acreage position that we have accumulated, we're looking at the tight sands in addition to the Floyd, which was conceptually our original idea in going in, to buy acreage in this area; it was a combination of tight sands and the Floyd shale. And we're just right now continuing to evaluate, and we have plans in 2007 to continue to evaluate that acreage in a large geographic area. So, it is early to speculate, and we just would feel more comfortable before we talk about it for us to understand a little bit better now also. Did I not answer your question?

Well, you managed to dance around it very nicely.

David Adams, Jefferies & Co.

A couple questions. In terms of the horizontal development in the Pettet, you did have a dual completion in the James line and Pettet, if I'm not mistaken. Can you give us a sense of what you saw, in terms of just within the Pettet formation, increase of production rate, and then relate that back to your expectations going into the James line?

Yes. We drilled -- our first well in the County Line prospect was a vertical well. We made a dual completion in that vertical well. The completed well cost was $1.8 million. We made a dual completion in the Pettet and the James. The James flowed about 2 million a day, and the Pettet flowed about 0.5 million a day. We went down to the south of that vertical well and drilled the horizontal Pettet well. That well cost us 3.3 million completed; unstimulated it came on at 3 million a day. So you can see the pickup from 0.5 million a day to 3 million a day in the Pettet.

South of our acreage block right now, and adjacent to it, we are currently participating as a nonoperator in a horizontal James well. We're approaching TD on that well. It's a 7000 foot lateral, as I mentioned earlier. And we would anticipate having that well completed in a couple of weeks, and would then be able to extrapolate from our vertical well down -- vertical James completion to the horizontal James completion. And that's going to set the stage for how aggressive we might be in 2007 in the County Line prospect.

And so, at 2 million a day vertically, horizontally what should we look for in terms of flow rate to really deem this test a success, or be encouraged at least?

I have -- if we get to -- if we double that rate, I'm going to be pretty excited about it.

Great. And then, to your reserves, can you give us a sense of what you were able to book in the Moxa Arch, given your down-spacing program?

We were -- because we're enlarging our program overall, some of our 2% pickup, or additional PUD bookings this year, some of that was the Moxa Arch area. I'm going to let Mike -- I'm going to let Mike kind of report what we did in the Moxa area on the PUD bookings.

We have, obviously, a bunch of locations that we could book. And we choose not to book everything, of course. But we -- we think that probably we'd be looking at 15 to 20 Bs, something like that, of bookings this year.

And ultimately, what do you think those bookings could grow to just from down-spacing alone?

Were you talking about bookings in 2006 --

(technical difficulty)

-- you could book, given the down spacing. What sort of potential do you have going forward to (multiple speakers) additional reserve bookings?

Okay. Go ahead, Mike.

We think on the Moxa, on the Frontier, that we could have 500 to 700 additional locations on 80-acre spacing, and we have booked a number of those locations. But because of our timing issues of our drilling program -- and we don't want to book more than about three years going out ahead of us -- we just keep a relatively low booking number involved with our year-end reserve numbers. But we do have -- we have booked a lot of probables; of course, those aren't booked [at the space for] proved. But, the probables number is very, very substantial up there right now.

And then lastly, and I'll hop off -- given your success in every one of your regions, your under-levered balance sheet, what do you need to see to really accelerate activity in the back half of 2007? And what sort of increase could we see in the CapEx number?

That's a good question. We have that internal discussion ongoing. And with a 17% debt to total cap number, we certainly have the ability to spend additional capital. And we're right now, of course, initially at a strip price. We're kind of within our anticipated cash flows with our current program.

What we want to do is get some early results from some of these areas, like County Line, for example, and make a determination whether or not it looks like that would be an area that we would expand our operations. We want to be able -- we have all our equipment and services secured for the program we've laid out. We want to be able to -- if we add to and increase our capital program, we want to be able to do it efficiently. But to look ahead, if you want me to fast forward and speculate just a little bit, if we had another $50 million to $100 million in our capital program by year end, assuming commodity prices stay relatively consistent, that would not surprise me.

(OPERATOR INSTRUCTIONS). [Havel Makonas], Raymond James.

More of an industry question for you. Given that you have such a diverse asset base, we've had some other operators talk about moderation, or in some cases, even declines in service costs. Can you talk about, across your asset base, if you have seen that, and if so, in which areas?

We have seen many flags, if you will, that indicate, certainly, softness in the service sector. We originally put together our budget for 2007, which was back in October of 2006, with an anticipated 5 to 10% increase. I would be surprised if in fact we see that 5 or 6 -- 5 to 10% increase this year. We have seen -- certainly, the operating group has received from calls on available rigs. I think some of the newbuilds are coming out, and they are replacing some of the older rigs, as opposed to being additive. With the same number of rigs and newbuilds coming out, but the same number of active rigs being consistent, you're seeing some of the stimulation crews, pumping crews, be more available. We are seeing an increase. In the last year, for example, we would submit proposals to have stimulation crews bid on our job. We might get one or two bids last year, with a fairly long leadtime before they could get to our location. Now we're seeing multiple bids come in on our stimulation crews, with maybe a crew available next week. So we're seeing those type of signs, indicating that service costs are certainly not going to have the inflationary pressures they had last year. We have seen this in, really, all our regions. I'll let Mike, you know, add some color to that in the regions we might have seen additional price weakness.

Thank you. Across the board in all of our regions, we are seeing a definite softening of the cost structure, especially on services and, of course, in rig availability. Canada has seen a marked decrease, obviously, from the changes up there. We are getting lots of phone calls, as Dan mentioned, from contractors who want to come in and drill wells because they have available rigs, which is quite different than it was six to eight months ago. I think it's interesting that this year in our budget we actually built in a 10% escalator for costs, and we probably will not see that kind of growth.

(OPERATOR INSTRUCTIONS). Monroe Helm, CM Energy Partners.

Good quarter. Two or three questions. Your production guidance for this year is up 12 to 18%. Is that what you said?

Yes.

That's just backing out the sales from last year. What do you think your underlying decline curve is at this point in time on the assets that you have?

We think the underlying decline curve for company-wide is approximately 15%.

Do you have, or can you discuss plans you have to drill in North Louisiana this year? Are you going to do anything on the (indiscernible) prospect this year, or anything else of significance?

I'm going to turn that over to Mike and let him talk about County Line maybe and -- excuse me -- the Castor area, and maybe Clear Branch, and any other activity we have up there.

We plan this year to drill four wells in our Castor prospect in North Louisiana. As you know, we had a nice discovery in [Hoston] Cotton Valley in that field this past year, and we're going to go ahead and start the exploitation of that program, of that field later on this spring. Four wells are all that we have planned in there at this time.

We are looking for potential drilling locations on our Clear Branch property. We did shoot a pretty large 3-D over that, and it has been interpreted, and now we're just looking for a place to evaluate going forward that acreage position. We also have other projects working in North Louisiana. And depending on where we see our program going, those opportunities may be evaluated later on this year, too.

Just back on Clear Branch for a minute, at one point in time that looked like it could be a fairly sizable prospect. Do you still feel that way after shooting the 3-D, or kind of what's your interpretation after the 3-D shoot?

Actually, the 3-D certainly told us why we drilled the first two wells, why they were not successful. And it really has given us a lot of insight on potential going forward, and we still feel that that could result in a significant accumulation (indiscernible)

Just one other question for Dan. Which of these -- fast forward into the year. Where do you think you're going to have the most upside surprises in your drilling program? What really [do you think] has the most excited that you could exceed your expectations on reserve adds and production?

Good question. With the sale of South Louisiana offshore, our drilling report takes on an entirely different light, that we're not -- we're not dependent upon one big pop to be able to make our year for us. I think, more appropriately, we would look at it more as program drilling. And with the size of drilling in the Moxa area, the size of our activity in the Minden area, from a program perspective, we're looking for those areas to yield some good year-end results, both on production and reserve replacement.

When we look at other areas, though, that might yield potential on the exploration side, or exportation side, we have some wells down that are in the McCampbell area that are some Frio wells that we could see some initial high rates attached to those wells. Canada is an area, in the Hinton area, that could yield significant upside opportunity. We have Narrow Way as an area that we have planned to exploit that could be some significant opportunities. Also, the Chime area could yield some of those opportunities also. So -- and then once we roll back into our -- get out of the drilling stip areas in the Paradox, we anticipate that the exploration program we have there, which is four exploration wells -- we think we could see some unique surprises up there in the Paradox also.

One last question. How much of your capital budget is for exploration?

Our capital budget of exploration is fairly small. I think it's about 35 -- what is it, Scott? He's shifting through it as we speak, Monroe. I might add a little color to the potential that we see in a number of our prospects, and it kind of gets back what Mike was talking about the Caster area. It kind of gets back to we only have four wells scheduled in that area. We have over 8000 acres and 100% acreage block. And you look at -- well, why not go and [assault] that area because of the success we had in the initial two wells there? With our portfolio, and you look at a $435 billion program, we have so many opportunities in our portfolio that it's hard to assault any, or all the areas that have the potential like that, because we're trying to balance the program in each region. And that would be an area, though, that certainly we have more opportunities than we're able to get to. And if we do expand our program, we're hoping maybe areas like Caster, County Line and some of the other areas would see expanded drilling potential as we go throughout the year. Back to Scott.

Monroe, the dry hole component of our program is $15 million.

15 million. Okay. One other question, if you don't mind. Given your balance sheet, are you actually looking at acquisitions at this point in time, or do you have enough on your drilling plate to not really spend much time there?

No, Monroe; we aren't focused on acquisitions. Obviously, if we saw something that made a lot of sense and it was within our current area of operations, we would entertain that. And if it augmented our current operations, particularly if it was under acreage we already had an interest in, we would certainly look at that. But our focus right now is just program execution on our organic program. We think if we can effectively deliver in this program, that we will be able to put up some very, very successful numbers at year end. And when you look at Cabot, at where it's trading right now, we're in the $2.30 in the ground, based on our current market price. And everything we've seen in the recent past is North of that range, if you were playing the M&A market.

(OPERATOR INSTRUCTIONS). David Khani, FBR.

This is Andrew Coleman actually, for a couple seconds. I wanted to ask one question. Have you had a chance to look at some of the PV10 numbers for 2006? Can you give any comments on where that might end up?

Can you be a little bit more (multiple speakers)

I guess the standardized measure calculations. How close are we to the 10-K coming out? Can you give any color on, I guess, what direction you're seeing the standardized measure going, and where it might end up?

The 10-K will be filed by the end of the month. The audit committee meeting is next week, next Thursday. And we'll try to file middle of the following week (multiple speakers) everybody's comments.

I had one clarification. When you were talking about the Devonian shale horizontal, was that lateral 700 feet? Did I hear right?

No. On our last horizontal well we drilled in the Appalachia area, we drilled 2400 foot laterally, and we drilled that well for $790,000. We have planned within the next two weeks a six-stage frac on that well, which will be approximately about an additional $180,000.

What makes it easier or harder, I guess, to put away the sand and stuff in the Devonian shale? I know it's a lower pressure reservoir.

I'll let Mike answer that.

Up in the Appalachian -- you're right there -- the pressure is low, so that makes our completions a bit more different than they are down in the Fayetteville or the Barnett. So up there we are using generally a foam frac, where we energize the fluid with nitrogen. And when we do that, we're able to flow the fluid back easier than if it was just a regular slick water or (indiscernible) type job. And that's how we are going forward. On this latest well that Dan mentioned, we are going to have -- use a higher concentration of sand versus the fluid, a little bit different than we had in the earlier wells, to see if we can get a better sand pack to enhance flow back out of the shale.

What kind of, I guess, half-length are you looking for? Can you comment on that?

About 1500 foot of total (indiscernible) length.

Great. Thank you. Last question. Can you give any color, I guess, to -- there were some revisions, a very small amount, that 18 Bs. And that was, I guess, mostly in the tail of the profile in Appalachia. Were they spread across all the well types that you all are drawing out there, or was it kind of in one special case, like more shale wells or more coalbed methane?

We have -- Steve Lindeman is in here also, who is our Director of Engineering and responsible for our reserve booking. I'll let him respond to that.

The revisions were spread throughout the areas. Everyone saw a price reduction from the -- year-over-year price reductions. But they were all equally spread.

I guess that does it for me. Thank you very much. It was a good quarter. Great F&D cost.

(OPERATOR INSTRUCTIONS). At this time there are no further questions. Sir, you may begin your closing remarks or continue your conference.

Appreciate it, Stephanie. As you can see, we have a significant program out in front of us in 2007. This is Cabot's largest program that we anticipate delivering. The results we anticipate to be fairly predictable with our low-risk nature of our portfolio. So, hopefully, as we go throughout the year, we'll continue to share positive news with you. Thanks for your interest.

This concludes today's Cabot Oil & Gas fourth-quarter and year-end 2006 conference call. You may now disconnect.