Coterra Energy Inc (CTRA) 2008 Q4 法說會逐字稿

Good morning. My name is Laurie and I will be your conference operator. At this time, I would like to welcome everyone to the Cabot Oil & Gas fourth quarter and year end 2008 conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions). Thank you. I will now turn the call over to Dan Dinges, Chief Executive Officer. Please go ahead, sir.

Thank you, Laurie. Good morning, thank you for joining us for this year end teleconference call. With me today, I have the members of our management team, Mike Walen; Scott Schroeder; Jeff Hutton, VP Marketing; Chuck Smyth, our VP Controller.

Before we start, let me say the standard boilerplate. Forward-looking statements included in the press releases we released last night apply to my comments today. As at this time every year, we have many things to cover and expand on from the two press releases that were issued last night. This morning, I will briefly cover year end financial results, year end operational metrics and then a more in depth discussion of operations, including our revised plans for 2009.

I'll make every effort to be brief so as to allow everyone ample time for questions following my comments. Based on the strength of the first eight months of 2008, Cabot Oil & Gas reported its best financial year ever; from a claims earnings perspective. With earnings over $200 million and with cash flow exceeding $600 million, the Company was able to pursue many opportunities and still maintain a strong financial structure to weather the current downturn we are in. While debt increased for our 2008 acquisition activity, our capitalization ratio remains around 30% and we plan to manage our 2009 investment program within cash flow.

In spite of the difficult environment, our 2009 program still allows for some flexibility, assuming commodity prices remain close to the $5 Henry Hub price we used in our revised budgeting process. Included in our financial results are some select items related to gains, impairments in stock comp. In regard to the gain category, it was a result of a settlement that involved both a cash sum, along with acreage, within one of our areas of operation. As far as impairments, these relate to producing properties and leasehold that, in the current environment, we'll receive significantly less capital.

The leasehold piece is primarily in the West, were based on the commodity price falloff and basis differential blowout and we may or may not get back to these exploration areas. And also in Mississippi, where our R&D project has had measured success, we have not scheduled additional capital in this area at this time. The largest portion of the producing property impairment relates to Trawick. And it is primarily a result of the carry on the first eight wells that was our cost to secure the acreage. This in no way condemns the effort we have ongoing in Trawick.

From a value added perspective, one of the key metrics to any organization growth in our industry is its ability to stack up reserves at economic investment levels. Cabot once again did that, growing reserves 20% year-over-year. The Company was able to add nearly 500 Bcfe before production and revisions, adjustments for the year. Importantly, two-thirds of the increase was from our organic drilling program with a drilling finding cost of $2.25 per Mcfe. Our revisions represent less than 3% of our year-end proved reserves and totaled 57 Bcfe, with 95% of this related to year-end pricing.

The acquisition in East Texas added another one-third of proved reserves, at an all-in cost of $3.46 per Mcf. Additionally, we accelerated our leasing effort to block up our acreage positions in the Marcellus in Pennsylvania and to add some new areas in East Texas, which obviously have not yet contributed any new reserves. All-in finding costs, inclusive of our leasehold acquisition, expenditures and producing property acquisition was $3.42. During the year, we added over 150,000 gross acres to our leasehold and to the hottest plays that our industry is in right now. Both of which, will see continued activity in this low commodity price environment.

In terms of production, the Company reported full year production of 95.2 Bcfe. This was slightly less than our 96 to 97 Bcf expectations. It was due primarily to some completion delays in East Texas. While slightly below expectation, this was still an 11% increase over our production levels in 2007.

Okay. Now, let me move to some of the operations conversation. Right now, our priority project in the Company is the Marcellus in Pennsylvania. Last night, we disclosed our year-end production rate, which was double our original year-end expectation and highlighted some well successes, with which we are very pleased. In 2009, we are focused on expanding our horizontal effort and moving it forward expeditiously. As stated, we have currently budgeted 30 horizontal and 30 vertical wells. However, depending on lease boundaries, et cetera, our objective is going to be to expand our horizontal well count greater than the 30 horizontal wells we have budgeted.

To that end, we have just hired a seasoned dedicated drilling engineer, he started this week, for our Marcellus effort. This is a position we have been searching to fill for nearly a year. His addition, together with the results of our R&D drilling effort there, lays a groundwork for an even more efficient drilling operation and a significant production increase in 2009.

In anticipation of our increasing Marcellus production, during the fourth quarter, the Company successfully secured additional firm outlet capacity with a phased-in back haul arrangement that will plateau at 90 million cubic foot equivalent per day in August of 2010 and runs through December of 2012. However, we will also be able to timely extend this arrangement at our discretion. Infrastructure is one of the keys in this play and we have solidified a great start to that process.

Because of the pricing outlook and our commitment to spend within our cash flow, we have essentially eliminated our drilling effort in West Virginia for the time being. Right now, we have only three wells scheduled for 2009. As most of you are aware, however, the vast majority of our 1 million acre position in West Virginia is already held by production.

Moving to East Texas. While I had hoped to be reporting two off the chart horizontal wells on this call, that did not happen. And as the press release highlighted, we are sciencing what occurred in the completion process. The results will determine our future action. One of our key questions in the area that we had complications, are the sliding sleeve external packer completion system that -- and trying to determine whether or not this is the right completion system to use in the rocks and the temperatures and pressures that we were making an effort to complete in. That's what we're trying to understand.

Though these two wells were our first two horizontal efforts in these zones, and I understand that new initiatives present new challenges. However, I am fairly disappointed we were unable to gather any more information than we did. Regardless, we will repeat this horizontal effort in the Haynesville line because of all the positives we have seen in our vertical effort.

As for the Bossier, we do not yet have the production data, similar to what we have in the Haynesville limestone. However, we are going to continue with our completion evaluation and determine what went wrong and how we can get a more effective completion in this shale. Again, I'm sure we'll have questions involving this area. I think this area was the focus point on new operations releases that the Street was expecting out of Cabot. And certainly, I am more disappointed, I'm sure, than the Street in not being able to deliver results.

At County Line, the deep vertical exploration project was successful. And while we are not disclosing the specifics of this, I will say that the pressures and the test data in the three zones that we tested, give us a great deal of optimism on what future we have in this area for the play. With these areas of focus in mind for 2009, we are going to drill 70 wells in East Texas. Of which, 20 are in Minden; 38 are in County Line; and 12 are in other areas of the region, including outside operated. Of the total $475 million program for 2009, this region in East Texas will receive about half of it.

With regard to Minden, many of you are aware of the pipeline explosion that occurred just outside of the DCP Carthage plant yard on February 11. The emergency shutdown of this plant and other plants did result in a net loss production to Cabot of about 20 million cubic foot for approximately one day. We were able to redirect 100% of our production to other pipelines by 6:00 a.m. the next morning. I certainly commend our marketing group for being able to get that done.

On a macro level, it is our expectation that industry activity will be significantly reduced in many areas across North America. However, I think capital allocation towards East Texas and North Louisiana, just as it is expected in the Marcellus, will remain relatively active. With this in mind and considering some of the bottlenecks that may occur regarding production in the East Texas / North Louisiana area, Cabot elected to hedge some of its basis in 2012 at the Houston ship channel. And you can find details on our Website. This action should mitigate some of our concerns, should we have a basis differential expansion in this particular area.

In the West region, though we still like our position in the Rockies and Mid-Continent due to the net back pricing, our entire West region effort has been cut back to simply meet our rig obligations, which expire in May of 2009. A total of 20 wells will be drilled in the West region under our 2009 plan. Also, the Company has opened a data room for our Canadian operations to explore industry level of interest in our niche position up in this area. This is by no means a fire sale, as we can simply cash flow our position if we choose. With our portfolio opportunities in East Texas and the Marcellus and our focus in those areas, I think it makes sense to consider this move.

A little bit of comment on cost. After undergoing significant cost inflations over the past several years, the exploration production industry is starting to experience some of the benefits that occur in a slowdown. Cabot's 2009 drilling, completion and operating cost structure is seeing the beginning of necessary reductions. Casing and other tubular goods have been reduced anywhere from 5% to over 21% so far, year-over-year. Drilling costs have reduced up to 40%, in some areas, on market based rigs. And Cabot is actively negotiating with our contracts to reduce those rates further.

Also, completion costs continue to be reduced. To date we have seen reductions of up to 15% to 20% and anticipate rates to continue to come down, consistent with the dramatic reduction in commodity prices. Again, we will continue to work with our vendors to reduce our cost structure. With mutual cooperation from all parties, we can reduce cost and continue to conduct an active program and add value to our shareholders.

Our first budget preparation for our 2009 program was back in October and we used a $7 and $70 strip price, which yielded free cash and a $600 million program. Today, many points have a $4 plus and $40 plus handle. We have revised our budget, using a $5 and $50 strip and reduced our program, as we've mentioned, to $475 million. That centers almost entirely on Pennsylvania and East Texas. This program honors nearly all of our rig commitments. Again, all of our rig commitments expire in 2009 and provides growth in reserves and production and provides free cash flow. One of the positives in this budget is our hedge position in 2009 that provides a great deal of our cash flow.

We are going to place our production growth targets at a 4% to 8% growth due to the economic volatility and lower investment levels. Though our production continues to grow, we have missed our guidance. However, as we continue to focus our program, I fully expect us to meet or exceed these new production targets.

Next week, we will have our year-end Board meeting with significant discussions centered on the effects of the rapid downturn that we've seen in our industry and what actions we will continue to take in light of our crystal ball look into the future. Because of our relatively conservative posture over the years, we are in a solid financial position, with numerous opportunities to drill economic wells, even in this low cost commodity price environment. We have limited risk of losing leases. We have no long-term costly rig contracts, except the ones that expire in 2009. And we have a leasehold position in several areas that yield some of the most attractive economics in North America.

The success of Cabot will, though, continue to be driven by efficient operations in the areas we will be operating. Before I open it up for questions I will simply say that we have posted some good numbers in 2008 and it added significantly to our reserve base, without leveraging our balance sheet. All of that is positive. However, also recognize that's yesterday's business. 2009 will have its challenges for all of us but we are very focused in two areas, both of which are in their very early stages of development. And we receive new data points every day. I do expect our report card in these two areas to improve as our learning curve also improves. With that, Laurie, I'll be more than happy to answer the questions.

(Operator Instructions). Michael Jacobs of Tudor Pickering Holt.

Good morning, gentlemen.

Good morning, Michael.

Some nice Marcellus results. Thinking about the Ely 5H, I believe for some time there was some concern on TOC getting high in the deeper Marcellus but it seems like it may not be an issue. Are you breaking the Marcellus into segments as you're moving deeper or is the organic content pretty uniform?

I'll let Mike answer this. Michael?

Yes, Michael, we've seen three different sections up there. We have an upper Marcellus, the Purcell the shale, the Purcell lime, plus the lower Marcellus. We've cut some cores, we've done the analysis and the TOC's are very attractive. And the rocks are not over cooked and I think that's the result of -- our wells are showing that.

That's great. And just wondering if we could just spend a second, moving down to East Texas and maybe spend a little bit more time on the Haynesville stem and talk about kind of what went wrong from a process standpoint, kind of lessons learned?

Well, and I'll flip it over to Mike also, but I'll do a little preamble here. We have talked a long time, unfortunately, about our new initiatives in the East Texas area. Looking at and trying to exploit a horizontal in the Haynesville lime, also looking at the opportunities to drill horizontal in the middle Bossier, which we've had significant shows in the -- just about every well we've drilled in the Minden area in that section. And we did the exploratory in the deep section in County Line.

But we really had, certainly with the vertical success in completions and production history in the Haynesville lime, we had high and still have high expectations for the horizontal in that section. We had drilled 40 or so wells or more in County Line using the Packers Plus system in our horizontals there. We felt comfortable using that system in our horizontals in the Haynesville lime and the Bossier shale. However, we -- and we did that.

Certainly, we experienced higher pressures and higher temperatures in the Bossier and Haynesville lime than we've seen in the James. And I don't know exactly what the problems are surrounding the Packers Plus system in our completion efforts. But in both wells, we had problems with the completions, whether sliding sleeves or whatever. But bottom line, we just did not get effective fracs. And I'll let Mike kind of explore on kind of what the industry really and probably what we'll go to in completions as we go forward to test these sections.

Yes. We looked at the Minden well in light of our experience in James Lime at County Line. Unfortunately, that seem did not work very well. We are now investigating, with some diagnostics equipment, on where these fracs went if we've got any fracs at all. And we're going to get that data and make a decision going forward, how we would complete additional wells in the lime and the shale.

The other -- some of our competitors out there, instead of using the external packers are actually now cementing their casing in the horizontal leg and pumping down plugs and perforating frac as they come out. And that seems to be one way to approach it and we're going to look at that right now, going forward. That will be something that we would investigate thoroughly, even with a horizontal well at County Line, probably in the Haynesville Shale, lower Bossier shale, in the Haynesville there.

So, I think that we have a lot to learn. It was kind of an R&D project. It didn't work out as well as we would like. But we're going to continue to make progress, I think.

That's great. I appreciate all that color. And so, when we think about kind of the $475 million program in '09 and East Texas receiving half of it, how much of that capital is being invested to test the Bossier, Haynesville? And kind of how do you think about balancing that with some pretty good Marcellus results, given low commodity prices and some of the operational issues?

Well, we are going to continue to try to find the right completion technique in the section below the traditional areas of East Texas. And basically, I'm talking about anything below the Cotton Valley. We'll continue to drill some of our wells vertical, where our spacing would not allow the horizontals.

But we will -- I don't have an exact number, Michael, on the dollars that are going to be allocated specifically for the Bossier/Haynesville. But we're going to spend whatever it takes to find the most efficient and best return method to complete in the Haynesville lime and certainly, explore the horizontal opportunities that we see in the middle Bossier.

Again, if we're completing vertical wells up to over 3 million a day, vertically in the Haynesville lime, and we're drilling an offset well horizontal with a, say, 3,000 feet of section open and have a 10 stage frac; I would certainly expect a -- better results than we've realized so far.

So, we have a ways to go. Again, my disappointment is that we spent a heck of a lot of money on these two horizontal wells and basically, we have zip to show for it. And now, we're back-pedaling and trying to figure out technically; Do we sidetrack? And then if we do sidetrack, is that the most efficient way or do we just drill another well? Or is there some salvage mode we can perform in the existing well bores? And that's going to be a primary project for us for 2009.

2009, in these commodity prices, completing Cotton Valley and Travis Peak wells are not going to get a lot of people excited. We recognize that exploiting the deeper section with horizontal drilling is where your best returns and recoveries are going to be and we're going to spend the money necessary to evaluate it.

Got you. Thank you very much for all that color.

Thank you, Michael.

Brian Singer of Goldman Sachs.

Thank you, good morning.

Hi, Brian.

Can you talk more about the County Line vertical test? I know there are some competitive reasons here. But can you give us a sense as to what you see as the potential for this? And is it something that is a new opportunity development? And maybe give us some additional color on whether this is just a small one-well opportunity or something that could be significant?

Well, Brian, if I sound like I'm dancing around some of the issues or results, I am. We have tested, as we've mentioned, three zones. And we have tested three zones at levels that would give us encouragement that each zone could be exploited for future evaluations with horizontal wells. So, how much area does that open up, I'll let you be the judge. The stratigraphy, the section is in a very thick overall section from the Bossier section down into the Haynesville section, is a very thick section. So differences in stratigraphy within that entire gross interval is going to be fairly consistent over, I would think, a large area.

Again, we don't have a lot of deep tests to make that correlation but we do have deep tests that have seen that entire strat section that we are correlating with. We certainly have seismic through the area that we can look at the overall section and we can see consistencies over a large area in the entire strat interval.

Brian, with the -- might be a question on what competitive advantage do you have with keeping information quiet? Well, we are leasing in the area. Others may continue to lease in the area. We're going to lease with actual knowledge and we'll base what we pay on a bonus per acre based on our actual knowledge. Others might lease in the area but they're not going to have the exact knowledge on what to pay per bonus and how much risk they're going to assign to the acreage that they might pick up.

So all I can say right now and I got ahead of myself when I talked about our new initiatives in the Minden area and we've tested these vertical wells in the Haynesville lime. And we were excited about a horizontal play in the Haynesville lime. And I've been talking about that operation for six months. And here I am at the end of the game, with wells completed and test results and I still have nothing to show for it.

That's not a comfortable position that a CEO likes to find himself in and I'm not comfortable with those results. I'm not going to get ahead of myself in talking about what good results we have in one vertical well in County Line. I am going to say that we're optimistic. And we've seen a thick section, high pressures in gas, but again, it's an area that we will probably duck our tail a little bit until we are able to show tangible results.

How many of similar wells do you expect to drill this year and have you assumed any production from any of that in your guidance?

Similar wells in the County Line area, Brian?

Yes, similar deep vertical tests, such as the one that you just did?

Well, we are not going to be looking at the County Line area and we have not budgeted any deep vertical tests in County Line. What we are going to do is, we're going to pick a zone and we're going to go horizontal in it. And with that test, we will make further amendments to our program as information will dictate.

Great. Thanks. And lastly, on the Marcellus, you did report pretty good production relative to your original expectations. There have been concerns raised with regards to both pipelines and permitting water, et cetera. Can you just give us a refresher on how you see that playing out over the next few months and 2009?

Yes. We have been pleased with what we've seen in our vertical completions in the Marcellus. We have, again, Marcellus wells that we initially brought online in July of 2008. The well -- and those were completions that were done in a different manner and not as efficient as the completion techniques we're employing today. But nevertheless, those wells are still holding up well. The new wells we're bringing online. And as we add efficiencies with completion techniques on higher pump rates and more sand, et cetera, we're seeing, again, positive results. The wells are holding up very well.

Even though we've seen a higher rate than we anticipated earlier on, I will say that I am still not pleased with us only having one horizontal well put into the pipeline as we speak. I've talked and Mike has talked to our East region for six months on affecting more horizontal completions up there. And our expectation was that we would have a little bit more horizontal completions to report. We don't at this stage but we're close to it. We have five horizontal wells drilled at various stages of completion up there and I do expect good results.

We have been fighting something that is unique, even though we've been up in the East for a long time. Northern Pennsylvania and particularly this year the early winter set in up there. And as you might be aware, when you bring 100 frac tanks full of water, you put them on location and the length of time it has to sit on location and the opportunities to freeze. And how you're going -- and the timeliness of frac and coordinating the logistics in a -- what for us has been a new, unique, different and fairly harsh environment with the cold, cold weather we've had up there. That has slowed us down.

And I'll give the guys that are fighting it in the field every day -- as I sit here on the phone, talking about disappointments on horizontal completions; those guys are fighting the frigid weather up there every day out in the cold. And I know we had one report of possible frostbites on hands, which we don't like to hear either. But it is reflective of the difficult environment we're facing up there.

But I am pleased with the Marcellus. And I think we have a lot still to learn but we also are seeing very significant results and we have, as Mike mentioned, a core up there. We have taken 400-foot of core throughout the entire section, Mike referenced, from the upper Marcellus through the Purcell, into the lower Marcellus. We're evaluating that core data and I think it's going to help us add efficiencies, with our completion techniques, as we continue forward.

Thank you.

Michael Hall of Stifel Nicolaus.

Thanks very much. Good morning.

Hi, Michael.

Kind of continuing on the Marcellus. Could you talk about what sort of aerial extent you've covered in your tests so far up in Northeast Penn?

Okay. Kind of looking at Mike on the aerial extent. But what we initially had done up there, Michael, we had drilled our first well back in 2006. We've stepped out a little over three miles, not quite four miles, to the North and drilled a test after we had secured a good leasehold position. Saw the consistencies in the entire section, upper Marcellus through the lower Marcellus. And we have been developing that kind of three to four mile square area at this stage. And that's what we're developing and certainly like what we see, and the consistency, what we see within this area.

Okay. And sorry to hammer on the pipeline issue. But just can you review for me what your export capacity kind of schedule is throughout 2009? You talked about getting up to 90 million in 2010. But where do you go from here to there?

Yes, I'm going to turn it over to Jeff Hutton, our VP of Marketing. But I will say that we have this back haul arrangement but we also have an arrangement that anything that does not go in the back haul, that goes to market towards New York, that we have a market in that direction also. But I'll let Jeff cover the details.

Okay. Basically, we have contracted firm back haul capacity out of Pennsylvania as a protection, to make sure our gas does flow each day. It does get phased in over the next couple years. I believe, here in early spring, we move from 20 million a day of firm to 40 million a day of firm. Approximately six months later, that goes to 60, it moves to 75. And by the time we get to October, we're at 90 million a day of firm back haul.

Okay.

Like Dan did mention, though, we are currently moving that gas forward into New Jersey. We've been pleased this winter that we've had no curtailments, no interruptions. And so we're anticipating we won't have any problems moving that production.

Okay. Thanks, that's helpful. And then, staying in the East, if I recall, you had some work you were doing in the Berea. Is there any color there or update there?

No, Michael, with the reduction in our capital, we did drill the horizontal Berea well. It tested over 1 million a day. We're pleased with the Berea results. We have a lot of running room down there. But with the reduced capital and commodity prices, we can only allocate in certain areas and we chose, in the East, that to be the Marcellus.

Okay. That makes sense. Thanks. And then corporate-wide, looking at the $475 million budget, you talked about kind of current cost trends. What sort of cost assumptions are you making in that, in terms of any declining line items? And if you get better cost reductions, would you apply that capital to the East or to East Texas or kind of what would be your thinking with that?

Yes, we used in our budgeting process 10% reductions in arriving at the level of activity we could conduct. And we would expect to see, with again, the prices in some areas being a little bit stubborn coming down, we would expect to see some more reductions on service costs. With the additional capital, if you will, and assuming that we stay within AFE's on our other expenditures, we would allocate in the areas that we are currently focusing our program. And that's East Texas and the Marcellus.

Okay. Any bias between either of those?

It would be just where the most efficiency could be gained. I would say that, with us trying to figure out two areas in East Texas and the horizontal effort, and we're obviously not there yet because we -- because of our failed horizontals in Minden. I would say that there is a likelihood that we would allocate to the East Texas area, to try to flush out the opportunities in the horizontal Bossier, Haynesville section. Probably more so than we would allocate greater sums into the Pennsylvania area of Marcellus.

Okay. Great. And then finally, just on your horizontals, as you look forward in East Texas, what kind of cost differentials do you assume between a Packers Plus and a kind of cemented cased, like people are doing in North Louisiana?

Well, I just -- this is Mike. I would have -- haven't looked at that in detail, but I'd make a swag that because of the Packers Plus, external packers type system is relatively high cost, I could see a significant, probably maybe a 50% or more reduction in just the cost of running the casing and cement versus using the external packers.

Okay. All right. Thank you.

Thank you, Mike.

Joe Allman of JPMorgan.

Good morning, everybody.

Hi, Joe.

Hi, Dan. In terms of the negative reserve revisions, I think it's 57.3 Bcfe, how much of those are proved developed and how much were PUD's. And could you talk about those? Were those tails or just did you lose some PUD's outright?

Looking at that detail. But we had, again, fairly low percentage when you look at industry and the write-downs that I've seen. 54 B's of it was directly related to pricing. And Steve, do have you the allocation of --?

Yes, I have the numbers, Dan. 54 B's were on the proved developed side and the other 4 B's were on the undeveloped side.

That's helpful. And could you -- what were they -- the proved -- it was just PUD tails or just in proved developed tails, pretty much?

On the PDP's, yes, it was primarily tails. There were some PUD's that we reduced because of pricing.

Okay, got you. Could you also give us a breakout of the cost? Because you gave us the F&D calculations in the release, but could you break out the development costs and the exploration costs? And then the acquisition of proved versus unproved?

Let me see if we have that breakout in front of us here, Joe. I tell you what. Why don't you call Scott.

Okay. Will do.

After the call and he can give you that breakout.

Okay. Great. Will do. Very helpful. Thank you, guys.

(Operator Instructions). Andrew Coleman of UBS.

Good morning, folks.

Hi, Andrew.

I had a couple of questions here. Could you first break down how much of the East Texas gas that you'll be drilling here over the future is going to go through which hub? Is it all going to Carthage or you're going to Perryville or you're going somewhere else?

Jeff can answer that, Andrew.

On the East Texas production, County Line and Minden, both end up at Carthage. Of course, there's about -- at Minden we have at least seven interstate pipeline take-aways from that particular DCP plant. And then at County Line, with Enbridge, we have, again, multiple interstate pipeline take-aways.

Okay. And then against a 4% to 8% production growth target that was mentioned earlier, I assume that East Texas and Appalachia will vary to the upside. Do you think -- or can you give any sort of color as to how much above that range that could be?

Well, we have -- as we allocate capital and, like some of the prior questions that Michael asked, if we had additional sums or we had some changes in capital allocation where would we do that? That's one of the reasons why we went to full guidance for the Company versus breaking it down by region.

But I will say that, with us only having one horizontal well in the Marcellus, we have not used a high rate for the completion of a horizontal well up there. I think we have a fairly good handle in what we've used on the vertical completions. And so, I would see -- I could see with effective horizontal completions, that we could maybe get some incremental from the horizontals in the Marcellus.

And we also have not really used any -- without having any data in the horizontal Bossier or Haynesville, we don't have any increases in -- we don't have any production attached to horizontal drilling in East Texas, except for our James wells and County Line. So, if we could add efficiencies through horizontal in the Bossier, Haynesville in East Texas, I could see where we could have opportunities there also.

Okay. If I could look at it from the other side then, as well. Could you give any sort of distinction on with Canada and the Rockies, maybe East Texas and Appalachia, as well, kind of what your ballpark base declines would be, given the 2000 rate exit? Are we on the 25% plus for all the regions, or do you think Appalachia because of its large well count and low pressure wells and their age is going to be somewhere in the 10% range?

I would say the 10% to 15% range is the range for the baseline decline.

Okay. And that would be the average then for the whole Company?

Yes.

Okay. Let me see. I have one more question here, just want to scan my list, make sure I find it. Can you guys tell us what the, either standardized measure or the PV10 was at year end or is your K pretty close behind this conference call?

2.4 billion, Andrew.

2.4 billion. Okay. Cool. If I could just squeeze one last one in here. The assets that you purchased in East Texas last summer were about 32 million a day. Can you give any update as to how those properties are performing today?

Yes, we've been kind of co-mingling our Minden operation up there, both on the acquired stuff and the historic legacy acreage up there. But Minden right now, combined, is producing 60 something million a day.

Okay. And I'm sorry, Scott, the 2.4 billion, that was PV10 or standardized measure?

PV10.

Okay, perfect. Thank you, guys.

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

Laurie, I appreciate it. And I appreciate the time people have given us in listening to the call. Again, challenging times out in front of us. And I think that our program will again add efficiencies, both in East Texas as we explore and exploit and try to develop the horizontals there. The Marcellus program, again, it passed this winter in some of the difficult operating environments, get the regulatory issues solved to allow us to put together a fluid program in the Marcellus. And I think we're going to be able to put together a good report card as we report in the future. I appreciate your time. Bye.

Thank you, that does conclude today's Cabot Oil & Gas fourth quarter and year end 2008 conference call. You may now disconnect.