Coterra Energy Inc (CTRA) 2008 Q3 法說會逐字稿

Good morning. I'll be your conference Operator today. At this time I would like to welcome everyone to the Cabot Oil & Gas third 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.

Mr. Dinges, you may begin your conference.

Thank you. Good morning, thanks for joining us for the third quarter teleconference call. With me today I have several members of management, Mike Walen, Scott Schroeder, Jeff Hutton, Chuck Smyth. Before we start, let me say the standard language and forward-looking statements included in the press release, that apply to my comments today.

Last night the Company issued two press releases covering the most recent quarterly and year-to-date financial results along with providing an operational update regarding progress and status of our Marcellus and Haynesville/Bossier programs. As highlighted, Cabot established another new high for its clean quarterly results, making third consecutive quarter this has occurred. This clearly sets up 2008 financially as the best in the Company's history. The $60 million of net income and approximately $150 million of cash flow from operations were the results of increased equivalent production levels and higher realized commodity prices. Even with the softening of commodity prices during the third quarter, Cabot realized a significant uptick in realizations with natural gas increasing 27% and oil growing 40%.

Cabot's hedge position while very robust in the current market was actually a negative to the price profile for the third quarter; however for the fourth quarter, both the oil and natural gas positions are expected to add considerably to our realization. At this time, the Company is 72% hedged on equivalent volumes for the fourth quarter and 54% hedged based on mid level guidance for 2009 which I will discuss in more detail in a few minutes. Production for the third quarter totaled 24.2 Bcfe which is the highest quarterly production level reported by Cabot Oil & Gas and over 10% higher than last year's third quarter. The Gulf Coast region is the driver of this growth with its East Texas successes and its acquisition which was somewhat offset by Hurricane impacts. The region production, however, was up over 30% between comparable quarters. The remaining regions were relatively flat as the West and Canada have less capital allocated their way and the East continues to transition its program towards the Marcellus based on the success we have realized which we will also discuss today.

With the historic changes in the economy, Cabot as I'm sure others has received many questions regarding liquidity. At the most recent balance sheet date, the Company had $165 million of capacity on its $350 million revolver. Thus far, in October, an additional $40 million has been drawn and we expect to end the year at about $100 million of capacity. With this market, Cabot continues to conduct its business in an efficient orderly fashion consistent with the way we have always done business. Each year we prepare our investment programs to allocate within cash flow and 2009 will be no different. We will continue to monitor the macro environment, the efficiencies of our investment and allocate capital accordingly. We will discuss the specifics of this allocation for each region.

In response to the market conditions and commodity prices, we have reduced some of our leasing efforts in select areas. We've delayed several wells, particularly in the West, and now expect our 2008 program to be about 450 wells and a spending level of about $750 million on the organic program. This figure excludes acquisition investment for producing property and leases which total about $450 million and which were funded with a combination of new debt and equity this past Summer. For the most part we will continue with our selected drilling program. For the remainder of 2008 and as such we will, we currently have 25 rigs operating and 17 rigs that are currently under contract. My Chief Financial Officer indicated I made a little faux pas here and said $450 million for our organic program -- for the acquisition versus what I meant to say was $754 million for our acquisition and leasing effort. Thanks, Scott.

As we discussed in the Gulf Coast, the Company started several new initiatives during the third quarter in the Gulf Coast area. Our primary effort revolved around continuing development of the newly acquired assets in the Minden area. To that end we have completed eight new wells testing the Cotton Valley. The well results have exceeded our acquisition model with an average IP of 1.5 million cubic foot equivalent per day and an EUR of approximately 1.7 Bcfe. Our average Cotton Valley well costs almost $3 million completed. We continue to be bullish on this play and we continue our drilling effort through 2009 with four rigs drilling on this property.

Additionally in the Minden area to exploit the potential we've seen in the Bossier shale and the Haynesville lines, the Company has drilled and cased two horizontal wells in these intervals. The first well reached total depth of 14,144 feet with a 3,800 foot lateral section drilled in the Bossier shale. The second well which was drilled from the same pad reached a total depth of 14,427 and that was drilled in the Haynesville line with a 3100 foot lateral section. We will stimulate both these wells with 10 fracs over the horizontal section, while these wells are ready for stimulation and we had pushed to have these wells completed prior to this call, however the operation has been delayed until we're able to access enough profit. This is a common problem the industry is seeing in several regions. We are aggressively searching for the supply with our vendors to secure 5 million pounds of frac sand needed for this completion operation.

Another new initiative is our deep vertical Haynesville test in the County Line area. This well was recently logged to a total depth of below 13,800 feet. We are encouraged with what we have seen in the deeper section and have run production casing. A completion operation will commence once we're able to line up the necessary equipment and secure the frac sand necessary. This test is a significant test as it could open up the deep potential which has not been evaluated under our County Line acreage.

Also in the Gulf Coast, a portion of our 2009 program will be focused on developing, development drilling in the County Line James play and the greater Minden Cotton Valley play. We will anticipate drilling 36 horizontal James wells in County Line plus 52 vertical Cotton Valley wells and five vertical Haynesville line tests in the greater Minden area; however it is important to note that should the completions in the two horizontal wells in the Minden area that I just mentioned be successful or the deep vertical completion in County Line be successful, you can expect us to reschedule our program to exploit the success from these new initiatives.

At Trawick, we continue to drill and test wells pursuant to our contract and will have drilled seven of eight obligation wells by year-end. We continue to see success in the upper Bossier shale, the Travis Peak, the Pettit, Cotton Valley and the Haynesville section in this field. One of the recent deep vertical wells this week has successfully tested a zone and is flowing to sell at a restricted rate of over 8 million cubic foot per day. Trawick has the potential to be a significant development area for Cabot in 2009. Throughout 2008 we have gathered extensive positive subsurface data at a considerable expense with virtually no cash flow generated from this effort due to surface infrastructure modification; however we're close to integrating all our successful wells into the existing pipeline system as progress has been made to speed up this operation recently. We anticipate near term sales rates to be plus or minus 15 million to $20 million per day gross.

Let's move to the East in the Appalachia area. First the traditional comments. The Company will drill approximately 220 wells in 2008. The majority of these wells are in West Virginia and are typical in field development wells testing the Mississippi and Sandstone in the Devonian shale. We continue to have nearly 100% success in this program which is typical and we will continue to drill these type of wells into 2009 although at a slower rate. In the same area but under a new initiative, we recently reached TD and set production casing on our first Borea horizontal well in Southern West Virginia this week. We expect more information to follow in the short-term from this effort.

The Marcellus play in Pennsylvania has become our focus for the future in this region. We kicked off our program in this play in earnest in 2008 where we had been very active drilling, laying pipeline and moving equipment into our Susquehanna project area. We have leased over 150,000 acres in our play to date and continue to expand our leasehold effort although currently at a slower rate. We have drilled 15 wells to date with five on production and 10 other wells in various stages of completion or pipeline connection. Additionally, we have five rigs drilling, two of them on horizontal wells.

At this time, we have started the completion with the first three of six planned fracs on our first horizontal well with very early indications which I've just received of production flowing to sales, approaching 3 million a day from just three of six planned fracs. This exceeds our pre-drill model. Two additional horizontal wells are also ready for completion. This play continues to give us consistent results from our vertical effort. The first five vertical wells currently producing are making a combined 4 to 5 million cubic foot per day and as previously mentioned we anticipate that we will have producing anywhere from 6 to 9 million cubic foot per day by year-end; however with the recent results, these initial vertical completions and now the most recent information regarding our horizontal completion, this projection could be on the conservative side. We have 100% working interest in all of these wells.

At this time, our well cost, production, and reserve profiles confirm our early estimate, although the horizontal well is certainly exceeding our estimate. Our well cost ranged between vertical wells $1.3 million to $1.5 million for a completed vertical well and $2.5 million to $3 million for our completed horizontal well. Early reserve estimates seemed to fall between 1 to 2 Bcf for the vertical test and 2.5 to 5 Bcf early estimates for a horizontal well. Our Phase I gathering system is scheduled to be finished by the end of November and we will immediately expand that system by 24 miles for gathering the 2009 drilling program.

At this time, with compression and existing pipeline tap in place, we're designed to move about 20 million cubic foot per day but with an additional tap, expected to be in place by the end of this month, in fact construction started this week and with our new compression order we will be expanding our take away capacity by over fivefold.

One question we get asked often is about the status of the water availability for drilling and completion. We did receive our SRBC permit as expected on September 11, for 3 million gallons of water per day. This volume will allow Cabot to drill and complete its remaining 2008 and all of 2009 program.

The 2009 Marcellus program will be a total of 60 wells made up of 30 horizontals and 30 verticals. We currently have five rigs running in the area and plan to max out at about eight rigs. We are able to expedite the drilling by having several smaller rigs drill the pilot holes, the vertical portions of our horizontal well, set casing and then move in larger rigs to drill the horizontal leg on mud. We've drilled several such wells and have seen a marked savings in time and money. With the premium we receive for natural gas over the Henry Hub in this Appalachia area, the high net interest we realize and the expected completed well cost, the EUR per well and production capabilities of this area, the returns for this project compare favorable with any other project area that I'm aware of. These returns are some of the highest in the Company. We expect to see positive results as we move forward and up ramp this program.

Moving to the West we will be reducing our capital exposure in this region for 2009 just as we did last year at this time due to the price received on the netback price received for gas; however as we mentioned in an earlier calls, certain initiatives have continued and the Company did conduct a 40 acre pilot test on the Moxa in the Rockies to test feasibility of a 40 acre downspacing to the Frontier. This pilot has been completed with four wells drilled from a central location. All four wells have been stimulated with the result similar to wells we drilled on 80 acre spacing. It is early time data but it appears that we are accessing new reserves at pressures typical for the Frontier. We will take more data points but if these wells hold up, we will be able to add considerable in field upside to our Moxa Frontier acreage. Clearly pricing and overall project economics will determine the future timing of further drilling. Also, our first Frontier horizontal well will be drilled during 2009.

In the Moxa, the Abbey 3416 Wildcat is drilling below 8400 feet in the higher Cattrell. We plan to see this well at total depth within two weeks before the drilling window ends. Moving to Canada, we are drilling the Hinton number 11 well, a two mile Southeast extension to the proven pool. We have penetrated the upper mountain park interval in this well and expect to reach total depth next week. In the same field we have just fracked the Mountain Park stand in the last well we drilled the Hinton number 10. The initial test looks promising with flow rates over 6 million cubic foot per day. It does appear the well may be choked back by frac sand in the well bore and we are moving in coil tubing to clean out the sand and retest. We are confident the rate will improve considerably following this remedial work.

In view of our 2009 market, certainly 2009 will be a challenging but I think rewarding year. Our program is anticipated to give us double digit production growth and still have spending remain under our discretionary cash flow. We have focused most of our effort in capital in East Texas and Pennsylvania Marcellus play with just over 90% of our program dollars. We feel these two plays provide excellent returns for our investment. We anticipate that the cost environment will be more favorable for the E&P sector in 2009 with marked reduction in price per drilling rigs, services, and people. We have already seen a softening in rig availability, some completion services, and casing availability and cost. Our biggest concern at this time is the ongoing shortage we're seeing of the profit available in East Texas and some of the West regions. While this does not stop our program, it obviously slows the completion operation.

Moving to our guidance, with our investment plans heavily weighted towards East Texas and Pennsylvania, our program guidance format will change to reflect production by quarter to the Company and away from regional reports. To that end, the new figures have been posted to our website and show a range of equivalent growth for 2009 between 14% and 17% on a $600 million program. This budget is run at 750 Henry Hub and $75 WTI and provides excess cash flow for the program. Additional expense guidance has also been provided. While there's definitely a change in sentiment in the market and this industry Cabot is predicting and proceeding as planned as we have historically. We have put together a program that falls within cash flow expectation and as we have done this every year. Any changes to our capital program will be dictated by market conditions with over 90% of our program allocated towards two high potential areas, Cabot is positioned very well for an outstanding year in 2009. Recent test results in fact just this week give us encouragement that our 2009 production profile could be enhanced. With that, I will be happy to answer any questions.

(OPERATOR INSTRUCTIONS) Your first question comes from Joe Magner.

Hi, Joe.

Good morning. How are you?

Good.

Just a quick question on Q4 guidance, with no change in your plans for '08 spending, could you maybe discuss a little bit as to where those reductions are coming from?

I'm sorry, in which period, Joe?

Q4 '08 it looks like guidance came down a little bit, just curious what the primary changes were relative to previous expectations?

Well, it was a timing, Joe. We have slowed down our activity in the West on the Moxa as well as other initiatives out there and of course we have also slowed down a little bit in West Virginia and those are the two main areas that we have slowed up in.

Okay, and then maybe a little bit more color in terms of '09. You've got an initial plan to spend $600 million which is well within cash flow and then as things improve or if things improve as we get into the year, how would that progress? Would you put more capital into East Texas and the Marcellus or would you reallocate some capital back towards the West and Canada?

No. Joe, I think it's at this time, depending on how the market improves and where it improves, with the activity level in East Texas and the Marcellus, we have a number of areas that we might be able to reallocate which we referenced a little bit in East Texas. For example, if the horizontal effort works in the Minden area or the deep tests work in County Line, those two areas could see additional capital allocated and kind of an amendment to our program also with this recent activity and well results we're seeing in Trawick with the well, the vertical well, that has tested and in fact flowing in the line over 8 million cubic foot per day, we're evaluating this and maybe further capital allocated in that area. And I might add also as a follow-up to your first question, the other slowdown a little bit in the last quarter, 2008, we did slide a little bit our expectations due to the lack of prop sand on the completions that we have scheduled in East Texas, so it's a shift versus an operational disappointment.

Okay, and I guess the last comment leads into my next questions. We are hearing a lot about tightness for profit and frac sand. What sort of, is there anything you can do outside of what you're already doing to address that or to improve your access to supply or is this just something the whole industry is trying to grapple with?

Joe, actually we have been pushing our vendors as hard as we can, and they are very very much aware of the issue. We've gone as far as to approach the manufacturers of the frac sand and the ceramic sand and of course, we didn't get anywhere there. We have heard that we are importing sand from Brazil now and there are ships on their way. Those boats aren't going to get here until next month, but it just looks like this is a response to the ramp up of these long reach horizontals across the industry that take a lot more, 10 times the sand that a typical vertical well would take.

Okay, and just is it frac sand or is it prop or a combination?

Well, it's both, typical white sand as well as ceramic sand, manufactured ceramic profit. They are both in the short supply.

Okay, and just my last question. Maybe a comment towards the end of your comments there, Dan, about moving to a Companywide production report versus a regional production. Is that, have you already made that change?

Yes. Our most recent posting, Joe, on the website has taken that into consideration and the reason for it, basically is with the way we're allocating capital and we're shifting capital certainly by choice and market dynamics, I just didn't want to have to indicate every time I talk about guidance, we've cut capital and production is pushed back and each region when in fact the impact is really on capital and gas corp.

Okay, that's all I have. Thank you.

Thank you.

Your next question comes from Brian Singer.

Thank you, good morning.

Hi, Brian.

Wanted to follow-up with a little more color on the Trawick vertical. Did you mention how many zones are involved in that 8 million a day rate and what the cost of that well is estimated at?

No, I did not, Brian. I'll let Mike kind of look up where the cost is but with this vertical well that we've just brought on and we're testing at restricted rates right now, it's from one zone.

And that's the deep Haynesville Lime?

It's a deep zone, yes.

So how do you think about the ultimate potential I guess, was that the $15 million to $20 million a day co-mingled with the up hole zones then?

Well, we have, right now, we haven't even gone that far. We have up hole behind pipe zones. We see some very strong pressures in this zone and we're not going to do anything except watch it flow into the pipeline right now. We would not, it is not our plan to shut a well in with this rate to a frac up hole and then open up ports and then co-mingle.

Okay.

So we're going to continue to flow this well, get good test data and all that and this well completed is right at about $5 million cost.

$5 million, okay. And so I guess what would be the next step if the rate continues to hold in line with expectations? Could you just talk about the additional drilling opportunities around the area?

Well, we have ongoing drilling and we have a couple other wells that have seen this deeper section and this is really the first good rate and test we've had and it's near term information for us and so we're pretty excited about what we're seeing but we're going to watch it a little bit and if things do hold up well, Brian, I think you'll see some additional activity.

Okay, and I guess between that well and I guess the initial indications on the horizontal Marcellus well, I know these are just two wells and potentially two of the better wells since you're highlighting them here but has that been factored into fourth quarter guidance or first quarter '09 guidance or is there upside if these rates hold in and you complete the other three zones or the other three fracs in Marcellus, et cetera?

Well, first off, we didn't go cherry pick these wells. These happened to be the only two wells that we had with our first horizontal in our Marcellus and our first deep test in Trawick, but with that being said, both of these wells have exceeded our pre-drill expectations, so we're excited about what we're seeing, and we get, say on the Marcellus, we've only produced half, we only frac half the well right now and we're right at 3 million a day from that completion. We're going to clean it up and then we're going to temporarily shut it in and then open up the remaining three purchase fracs and frac this next week and then open it back up, so we're excited about what we're seeing up there. Again, it's -- we had some pretty good numbers on pre-deal expectations but we're excited about what we're seeing on our first effort there and this test in Trawick is equally exciting for us. Along with the deep log we have seen in County Line.

Yes, okay. Thanks and lastly, I know you're speaking less regionally in terms of guidance but how should we think about Rockies production next year, given that reduced investment there.

Well, I think don't hold me to this Brian but I would say that production just purely out of the Rockies would be anywhere from 3%, to 4%, 5% down.

Great. Thank you.

Yes.

Your next question comes from Michael Hall.

Thanks. Just kind of drilling into the Marcellus a bit more, in the first three wells you've drilled, can you talk about any sort of, did you run into any difficulties in the horizontal leg and drilling into the Marcellus, was there any issues that came up?

Well, I'll let Mike go into a little bit of detail on that. I will say that of course this is obviously a greenfield effort up there and we learn and expect a learning curve throughout this process just like they are still learning things in the Barnett and the Fayetteville, but the five vertical wells that we have producing, we learned a couple of things in those wells. I can say that the zones that we have identified as potential in the vertical wells in two or three of the wells, we did not affect full frac potential in two of the three, two or three of the five wells that we have producing right now, and that was for various reasons and Mike can go into details if we need to, might be a little granular but so those five wells even though they're flowing very well, we did not have 100% completions in those five wells.

On the horizontal well, we had delays with the rig and the rig was too small and the first rig we had on it, we tried drilling that with air versus mud in the beginning and we decided well we don't need to do that, let's move the small rig off and move a larger rig back on and once we did that we drilled basically without any trouble to a TD on that well.

So you ended up using mud, not air on it?

Yes, we did. In the horizontal section. Mike might want to add in here.

And the reason that we went to mud was because we found the pressures to be too high for it to handle the air and we couldn't keep the hole open, so we had to mud up and go to relatively high mud weights to keep that hole open. Once we did that everything was fine. And to come back to Dan's comment on the vertical wells. We didn't have mechanical problems for not fracking everything. We chose to be selective where we would do our initial fracs and what the logs were showing us. The other zones that we have seen are still there to be completed in the future.

Okay, great. And then in terms of the gas, what kind of BTU contents are you seeing or do you think you'll need processing capacity in the Northeast or is it looking pretty dry?

No, it is pipeline quality gas, very low inert, right around a 1000, a little bit over a 1000 BTU.

Okay, great. And then finally, you talked about 2.5 to 5 B's per well on the horizontals and $2.5 million to $3 million cost on the three initial obviously it's very early but you talked about the first with only three stages being above expectations. Would it be above that 5 B expectation or is that kind of more reflective now of the initial result out of that first well?

Well, the range we've given you can drive a truck through.

Yes.

But we just, heck we're just getting this information in and so it's a little bit early to speculate out there but we're really pleased with what we're seeing. I would say overall and I'll take this moment if I may, Mike, make a comment. Overall, what we've seen out in the Marcellus is an effort to get equipment in our pipeline done and get locations built and get the infrastructure in place and get people up there and the appropriated equipment and decisions on how we're going to drill and where we're going to drill and do we drill from two pad, one pad, two wells or how do we go about this operation and frac techniques and recipe and all that, I guess my frustration is and maybe I don't have the appropriate patience but it's been a little bit slow. I would have expected our horizontal effort to be a little further along than it is right now. We were delayed for some of our own reasons and we were also delayed though significantly for regulatory reasons up there. So we're a little bit late. I was hoping to have more color at this conference call but I'm glad we could get in half of this horizontal well report.

Also in the East we have many initiatives with the horizontal wells. I was hoping to have information on those in the Minden area. We knew we were probably not going to have the in depth information except maybe the log on the County Line deep test and we were glad to get the new information on Trawick. So my frustration just comes in everything in Cabot's program right now that has a lot of visibility on the horizon for us and certainly, potential upside is just it's still new information but what we're seeing, it has met and in most cases exceeded what we've been looking at.

Thanks for the color. If I may one more just on the rig count. Companywide, you plan to drop any rigs in 2009 as you bring spending in a bit and then also it sounded like maybe you're adding some rigs up in the Marcellus. I just wanted to confirm. Are you going from five to eight or where is that at?

Yes. We'll have five kind of up there consistently and as the weather gets better, we'll move in a couple more rigs, when the weather is better for some deep drilling and then probably once it gets, the weather gets bad towards the winter of '09, we might lay down a couple of the rigs up in Appalachia but maintain at least five rigs up there and as far as the 25 rigs we have running now, we don't have, besides the information we've given on the West we don't have plans of laying down too many rigs.

Okay, great. Appreciate it. Thank you.

Thank you, Mike.

Your next question comes from Andrew Coleman.

Good morning folks.

Good morning Andrew.

A couple of quick ones here. Just looking at the use of the lower horsepower rates that drilled some of the vertical sections, could you like give a rough break down as to I guess the number of days that you can use that rig for of the total days used to drill? Are you getting like 50% of that well? Is it 20% of the well?

Andrew, our best effort up there in the Marcellus with the vertical well drilled on air was about nine days to get down to just above the Marcellus at our seven inch and then we go out and drill the horizontal leg and we can generally drill these wells in under 21 days, TD, so it's using the small rig to do the service hole, really speeds stuff up.

Do you have additional opportunities as you look across your portfolio to use that same style of horsepower rig to save cost, save time?

Well, of course we use that style of rig to drill all of our wells in the West Virginia, so that's just something that we always do. Generally speaking, like at County Line where we're doing a lot of horizontal James drilling, really we have found out the E&P rate for our typical rig there will kind of give us the same kind of penetration. We don't see any value of putting on a small rig and then moving off there because we can get those rigs drilled in a good order with the current set up we have. I would say using the shallow rig would be really most applicable to the Marcellus in Pennsylvania.

Okay, all right and looking at that I guess base declines and then across your assets it was said earlier on the call that you expect to see about a 5% decline in the Rockies. I guess could you just go over what you guys do to I guess keep production that flat I guess given only 10% of CapEx is going to that region of the country and is it increased work over activities or what?

Well, we haven't shut down all activity in the West, okay? So we are going to be drilling some wells in the West. We are going to be doing some workover work but also remember that the decline rate, our base decline in the West is only what, 8% to 12% depending upon where you are, so it doesn't fall off too badly.

Okay, all right, thanks very much.

Thank you.

Your next question comes from Jack Aydin.

Hi, guys.

Hi, Jack.

Dan and Mike, of the pipe rigs that you are using, the number is small. How many of them are small, how many are capable of doing the horizontal leg?

We have three rigs capable of doing horizontal up there right now. And two of these small rigs.

And if you go to eight rigs, you will have horizontal rigs or the small rigs? If you have the three?

We're still working the plan, Jack, but you can expect that we would look for probably two more of the larger rigs to drill horizontals and then one more of the smaller rigs for the verticals.

Okay, and Mike, you mentioned that you have 150,000 now in the Northeast in a sense in the Susquehanna area. How much acreage do you have in the Southwest to the Marcellus?

In what area, Jack?

In the Southwest area of the play, you know.

In Southwest PA?

Yes.

All right we probably have in Southwest PA probably only about 5,000 acres. That's blocked up in essentially two small areas. We really did not focus on, nor did we want to get into a bidding match with the long term first movers in Southwest PA, so we didn't really get in there.

Okay. Then it's the economics and return, internal rate of return and based on what you mentioned on the IP, the potential, why not accelerate the activity in more than 30 horizontal wells in the--?

Well, it's a valid question, Jack, and keep in mind we built this plan and presented it to our Board just this week and we built the plan still with the expectation that we, based on our models that we had confidence in our models, we still hadn't seen the rates from our first Marcellus well, horizontal Marcellus well, and additionally, we have an infrastructure, equipment. We have bought acreage up there for a building site. We're building our yard. It is our every intent because of the superior economics and returns on a play like this, we have every intent to continue to expand our capital dollars allocated up there, but at this stage, we thought that the 60 wells, 30 and 30 vertical versus horizontal and all of the other moving parts we had and uncertainty about the regulatory process that that was a good starting point.

Thank you.

Yes.

Your next question comes from Ellen Hannan.

Good morning. I just have a couple questions for you. Dan, in light of your capital program for 2009 and keeping in mind the drilling results that you've had so far, how do you feel about your 235 to 260 F&D cost range?

Well, as it's fairly early to make that estimate, but I feel pretty good about it. Some of the uncertainty certainly is how quick service cost will come down and we feel fairly confident they will come down. I might add that just as a precautionary measure in our budgeting, we actually put a slight increase in our budget profile for our service cost over and above what we have realized in 2008. So that number, 235 to 260 does include a slight -- hello?

Hello.

Well, I guess somebody got off and their line is open. I'll continue talking. Anyway, the 235 to 260 does include a slight increase in our capital program over 2008. So painted differently if costs come down and results are enhanced, then you could see that number move.

Okay, and one other quick question for you too. One area that you've not made any mention of at all concerns your properties in Canada. What are your thoughts on that longer term?

Well, Canada's focus has been in Hinton, we have the, what's interesting about Hinton, I didn't go into any detail about it but what's interesting about Hinton is that this well we're drilling now is a two mile Southeast offset and it's across the River from where we've been drilling and all of our drilling to date has occurred on the West side of the town of Hinton and the West side of the River, and we've jumped the River and we jumped on the East side of Hinton and where we have a significant acreage position over there in the Southeast side that we have covered with our 3D and whatnot, and this is going to be a very interesting well to expand and prove up a considerable amount of acreage in that particular area. So we're looking forward to those results and with those results, we could modify our program up there also.

Just one last question on Canada. Do you expect the Canadian operations to fund their own cash flow or do you allocate more capital to Canada than--?

Nope. We're expecting Canada to fund not only their program but we expect the Canada cash flow to help fund our East Texas and Appalachia operation. That's our expectation.

Great. That's it for me. Thank you.

Just one moment for your next question.

Hello?

Yes, sir, just one moment. Your next question comes from David Heikkinen.

The Bossier shale and then the lime test, can you talk some about the depositional environment? Are you seeing consistent deposition in the Bossier shale across your acreage?

David, you were not opened up to the speaker here on the earlier part of your question.

Oh, okay, I'll repeat it.

Thank you.

Basically just thinking about the Bossier versus the Haynesville and trying to frame up depositional environment and consistency in the Bossier shale as you move into your acreage, I know there isn't the Haynesville -- or you're testing the Haynesville now and County Line, but just trying to understand consistency and kind of properties and then next on the lime, normally it's too tight so is there a cutoff as far as what you're seeing with the horizontal lime well that you drilled? Just trying to understand that too.

Well, David, we have drilled numerous deep data points that are giving us Bossier/Haynesville shale information. We are seeing the Haynesville shale, if you will, extend over all of Cabot acreage. It is not as thick as we would see over in Louisiana. But the properties, the gas content and so on are the same. More importantly from our perspective is that we are seeing what we're calling the middle and upper Bossier as very thick, very gas charged. We are producing a well right now from the upper Bossier shale at nearly 3 million a day. We talked about it earlier at Trawick at the last conference call, that well is actually improving. And we're confident that the horizontal Bossier shale which is in the middle Bossier interval is drilled in a shale that is rich in silica and quartz and in carbonate, low in clay content. This shale should stimulate very effectively, probably better fracked in the efficiency that you might see in the more play rich Haynesville shale and I think some of the anecdotal evidence that we've seen from other Operators suggests that this middle and upper Bossier which may not be getting the big press that we're seeing from Louisiana is going to be a significant contributor to the entire Bossier shale play in East Texas. So right now we're very optimistic on what we've seen so far both from rock properties in the Bossier and the Haynesville shale as well as the production and test rates and gas contents that we've seen to date.

So really, just trying to summarize you guys testing the Bossier and favoring it, it's really the economics of the Bossier because it's thicker and the Haynesville has thinned out. It's not that you're not seeing Haynesville. It's just thinner so your economics are better in the Bossier in your acreage probably than they would be in the Haynesville?

Well we have seen some data that suggests now from vertical wells and I think that these are horizontal plays, we have seen some data vertical wells from the big thick Haynesville shales, big thick 200 feet thick or more that the initial rates after frac are not all that big. I mean, 1 million, 1.5 million a day. So you can say that where we're drilling although it is thinner that similar type of rates had been established by up in the Minden area with a well that was drilled by the former operator of the property that we bought. So we think that there's still a lot of upside left, in the Haynesville even though it is thinner over in the Minden area.

Okay, so maybe I'm reading too much into your decision to test the Bossier and the lime first. It sounds like you're going to test the Haynesville on your acreage as well as beyond just the vertical well?

Absolutely we are.

So can you give any thicknesses as far as what the Haynesville and Bossier are on your acreage as you move to the South?

We're seeing Bossier and we don't break it out into the so-called Haynesville. I don't buy the terminology. It's all Bossier. It's between 750 and 1,000 feet thick and it's all gas charged.

So you don't, okay. We can follow-up. Thank you.

All right.

Your next question comes from Joe Magner.

Thanks. Just a follow-up with respect to some comments made about development plans, currently running around 25 rigs and aside from slowing down or laying down some in the West, you're going to keep things pretty consistent. Can you remind us what your average rig count has been throughout 2008?

Probably average 22, plus or minus.

Okay, so I guess how do we think about if you're going from 22 up to possibly somewhere in that range for all of '09, CapEx for this year around 750 dropping to 600 and you're budgeting service cost increases, where are the savings or where are the reductions really going to come from? Is it workover expenditures, is it exploration efforts that might be slowed?

Well, we certainly have reduced our leasehold considerably. That's one of the areas we've reduced. Our seismic is another area, and actually, on the drilling side, we've reduced our drilling capital probably close to 12% to 15% just on drilling dollars is all we've reduced the drilling portion of our budget to 2008 to 2009.

Okay, and maybe I heard incorrectly earlier. I thought there was a comment about how acquisition and leasehold spending was not included in the '08 budget, the $750 million budget?

That's right.

Okay. Thanks.

Yes.

Your next question comes from [Drew Benkar].

Yeah, hi, it's actually Eric Hagen from Merrill Lynch. A question on the attach rates you cited. Are those 24 hour tests, instantaneous rates just to give us an idea of what time period you're talking about?

Excuse me, Eric, which well?

The Marcellus well and the Haynesville Lime.

Both those wells are flowing into sales.

So you're producing the Marcellus well to sales right now?

Yes, let me back up. The five wells that we had -- that we put out on the press release are all vertical wells and those five vertical wells are producing between 4 and 5 million a day.

And the horizontal well?

The horizontal well which is, they have been cleaning it up, tweaking it, shutting it in, turning it on, shutting it in, turning it off and they've now turned it on and got some of the frac sand back and some of the water flow back and all that. They've turned it on and they have now put and as they cleaned it up, they've now turned it into the sales line and it is approximately 3 million a day by itself.

Okay, thanks. And then in the County Line, the James Line play, any updates there, any recent well results and just to look back on how wells are performing there relative to your model?

Yes, Eric, we configured the program, our most recent completion was around 12, a little over 12 million a day, same pressure profile. We again are averaging and we've drilled approaching 40 wells now. Our average is still almost 11 million a day IP with about a 5.6 million a day average 30 day IP. So the well results are being very very consistent across the field and we anticipate that to hold up going forward.

Okay, and looking forward to '09 Mike, what's the program look like there again? Is it going to be--?

I believe it's 32 wells I believe it is horizontal James wells in County Line.

Okay, great.

And I have three rigs running in the field, maybe a fourth rig in and out but we'll keep that level of activity for most of the year.

Great. Thanks, Mike. Thanks, Dan.

Thank you, Eric.

(OPERATOR INSTRUCTIONS) Your next question comes from Michael Hall.

Yes, thanks for the follow-up. Just real quickly on the CapEx, I was wondering how much of the 2009 budget and maybe how much of 2008 as well relates to kind of midstream spending, gathering compression pipeline.

I'm going to let them shift through their notes here, Mike.

Thank you.

Yes, Mike? We're looking at for total pipeline and gathering about $34 million in '08 and about the same level in '09 and then up in the facilities production equipment line, we're looking at about, well that number is pretty high in '08, about 27 million and it will, it's about 31 million in '09.

Okay. Very good. And then the DD&A rate kind of in the guidance, it's a bit higher maybe than I would have thought. Is that predominantly related to the Minden acquisition?

Yes, it is, about $0.25 plus or minus is related to the acquisition.

Great. Appreciate the color. Thank you.

There are no further questions at this time.

Okay, appreciate the questions, the interest. We're certainly looking forward to a better commodity price environment if we can find that but as far as our organic program when you look out what we have in front of us with the most recent data, and color, we've been able to add the still some pending data with the two horizontals and the Minden area, the deep test and the County Line and incremental adds on production in the Trawick area and we anticipate a couple more horizontal wells to be completed in the Marcellus very near term and also our horizontal Borea well up there in the East, pretty excited about what we have out in front of us and appreciate your support. Thank you.

This concludes today's conference call. You may now disconnect.