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Cabot Oil & Gas Corp. (NYSE:COG)

Q2 2008 Earnings Call

July 25, 2008 9:30 am

Executives

Dan Dinges - Chairman, President and CEO

Mike Walen - SVP and COO

Scott Schroeder - VP and CFO

Jeff Hutton - VP of Marketing

Henry (Chuck) Smythe - VP Controller and Treasurer

Analysts

Joe Allman - JPMorgan

Brian Singer - Goldman Sachs

Ellen Hannan - Weeden & Co.

Eric Hagen - Merrill Lynch

Andrew Coleman - UBS

Jack Aydin - KeyBanc Capital

Larry Busnardo - Tristone Capital

Sarah Spencer - Quartz

Larry Benedetto - Howard Weil

Operator

At this time, I would like to welcome everyone to the Cabot Oil & Gas second quarter 2008 conference call. (Operator Instructions).

I will now turn the question over to Mr. Dan Dinges, Chairman, President and CEO. You may begin.

Dan Dinges

Thank you, Chasity. Appreciate all of you joining us for our second quarter teleconference. I have our management team with me today. Mike Walen, our COO; Scott Schroeder, our CFO; Jeff Hutton, our VP of Marketing; and Chuck Smyth, our VP Controller.

The Board applied language and forward-looking statements included in our press release do apply to my following comments. Cabot issued two press releases last night, as most of you probably read, regarding the quarterly financial results and the operational update, with some recent operational successes and our current efforts in the Marcellus and Bossier Shale's, which I will expand on later in our discussion.

Financially, the company reported an excellent second quarter, with approximately $70 million net income after removing the expense associated with stock compensation that is driven by FAS 123R valuations. This does represent record second quarter results for Cabot. Higher production levels and higher prices contributed to the increase in performance year-over-year from a clean earnings perspective.

I would note that the major contributor to the select item was stock plan payments to our non-officer employees. This reduced cash flow per share about $0.14. The stock compensation expense relates to the finalization of a non-officer employee-based incentive retention plan that paid a portion of their base salary when predetermined stock targets were met. The targets were met and the total payout to the non-officer group was $15.7 million pre-tax.

The company's production increased nearly 10% from last year's comparable period and had a 5% increase quarter-over-quarter, led by volume increases primarily from our west region.

The east region was relatively flat, as we continue to allocate resources away from our traditional areas in West Virginia towards Marcellus development, including the resolution of inherent startup issues that we have experienced which really should be expected when developing new areas, especially developing those areas where there has never been E&P operations of any magnitude.

The Gulf Coast met the expectations, but more importantly, it is positioned to increase base volumes and will also see the additions of the acquired volumes for a portion of the third quarter following our imminent close of this transaction.

As we prepare our 2009 program and budgeting process, we have our challenges ahead of us to determine the focus of our capital allocation. As I had mentioned in the past, we have a number of new initiatives, i.e., wells that we are currently drilling, that we have recently collected information and we also have initiatives that we are currently awaiting new information.

The good news is that this is a high class problem. We are going to have a decision on selecting which pool of opportunity we will be allocating capital as we move into our 2009 budgeting process.

As mentioned, we are in the process of shifting capital from our traditional vertical well program in the east to our Marcellus expansion in Pennsylvania, and also expanding our East Texas Bossier effort. Clearly this will impact volumes, production, from each area. However, this shift to capital will increase the company's production profile overall as we move forward. It is going to be just a matter of what volumes, quantity of volumes come from which area.

For the third and fourth quarter, production guidance levels have been increased. This is primarily due to the planned inclusion of volumes from the acquisition for the Gulf Coast starting in September.

This is somewhat offset by the lowering of our east volumes due to what I just mentioned, redirect of resources and also to the regulatory delays relating to water. And we did reach a milestone yesterday with the industries, first Marcellus production flowing to sales in Northeast P.A. I will cover a few more details when I get to the east operations discussion.

As we announced last night, the capital level, excluding the acquisition related to costs was increased to account for the extensive leasing activity or the extensive land-grab that industry is experiencing right now, plus the additional drilling activity. Right now we expect to drill a total of 516 gross wells for the year and 536 total wells, when you add the acquired properties to this account.

Now, I will be slightly more grainier discussing each region. In the west, through the first half of the year, Cabot has drilled 61 gross wells, and without a dry hole. 72 wells remain to be drilled for the remainder of the year. We have drilled 26 Chester wells, 15 Morrow and 20 Frontier wells across the region, with an indicated drilling finding cost of less than $2.

The company has two rigs running in the Wyoming Moxa Arch area, plus two rigs operating in Oklahoma. We plan to keep this level of activity for the remainder of the year and into 2009.

So far we are very pleased with the results we have seen from our Mid-Con and Rockies drilling program, and we do expect this level of success to continue into 2009.

On the exploration front, we have finished drilling the south Gypsum Wildcat that we have talked about several times. We were delayed in completing this well with the drilling step regulations, but we have reached total depth. Production casing was set over that (inaudible) well lateral and we have completed the well. We are currently flow testing and obtaining pressure data to assist in evaluating the extent of this discovery. So far, we are cautiously optimistic, although additional testing will be necessary prior to constructing pipeline into this area.

A second well has been staked and we have initiated the permitting process. Later this fall, we will, this is also in a Paradox. We will spud the Abbey Wildcat. This 9000 foot honker trail test will evaluate a large seismically defined structural feature that is northwest of our Double Eagle field. Cabot will operate this prospect with a 25% carried interest.

Cabot also plans to initiate in the Green River basin, a test of Lewis Shale potential and its Lookout Wash field with a horizontal well to be spud in October. If this horizontal test is successful, we will set up an additional horizontal exportation on about 7000 acres in the field. Cabot will have a working interest of 45% to 80% or so in this 7000-acre area. Again, this is our first horizontal effort in the Lewis Shale in the Green River basin.

Moving to the Gulf Coast; the company has drilled 35 wells during the first half of the year and experienced a 94% success rate. We drilled 16 wells in County Line in the first half of the year which brings a total of 27 horizontal James wells in the field.

Now, we also have drilled seven Trawick wells, four of those being outside operated and four Minden wells. We also had some activity in south Texas, as well as some additional activity in our Mississippi acreage position. We have six rigs operating in the Gulf Coast region at this time, two in Minden, where one is drilling a horizontal Bossier test. We have two rigs at County Line, a rig in Trawick, and a rig working in Mississippi.

We will also add two rigs later this year, or this summer I should say, into our County Line field. Additionally, there are four rigs drilling for Cabot's account at Minden on the pending acreage acquisition position.

Our focus continues to be in East Texas and north Louisiana, an obvious response to the new opportunities we see associated with the Bossier/Haynesville Shale play. We have approximately 135,000 acres in this play, in both states, while our three main project areas fall within the play fairway. Competitor activity, as well as Cabot's work has demonstrated the shale potential in this area.

As I mentioned it at Minden, we are currently drilling middle Bossier horizontal test. This well will reach total depth within ten days. This well is testing a zone equivalent to that reported by an operator in Harrison County recently. So far in drilling this well, we have encountered encouraging gas shows while drilling.

Additionally at Minden, we will also exploit the success of a recent vertical well in the lower Bossier, i.e. Haynesville shale, and middle Bossier drilled by the operator; the properties we are acquiring. The well that they drilled tested both zones at a combined rate of 1.6 million cubic foot per day from, again, a vertical well bore. Cabot will be drilling an initial horizontal test to evaluate these shale zones, on the acquired acreage in the very near future.

The Haynesville Lime continues to show excellent results from vertical completions in the Minden area. As we reported earlier, these deeper tails under the traditional Cotton Valley wells yield up to 1 to 1.5 Bcf of the incremental reserves with up to 2 million cubic foot per day plus of incremental IP at a cost of $200,000 to $400,000 over the typical Cotton Valley completion.

The economic returns are very attractive, but we think that a horizontal exportation of this fractured lime section could make this play even more attractive to us.

To that end, the company plans to drill a horizontal well to test the Haynesville Lime, immediately following our Bossier horizontal test which is as I mentioned currently drilling. In fact, as we discussed in our operational update last night, we plan to utilize the same pad, skid the rig about 30 feet and spud this well, after completion of the Bossier horizontal. Both well bores will be completed back-to-back and we anticipate first production from the first completion in October.

The recently acquired properties at Minden continue to be exploited at this time by the operator with a four-rig program drilling for Cabot's account. After closing this transaction, obviously Cabot will take over operatorship, and we will continue with the program but will modify it somewhat to start development of the deeper Haynesville and Bossier Shale potential. We view these properties to have significant resource opportunities in these zones, which certainly would be accretive to this acquisition.

At Trawick, we continue our one-well drilling program. Obviously, as I have mentioned we are restricted to one rig as we are targeted to drill, moving towards drilling eight earning wells, most being planned to the Haynesville. To-date we have drilled three earning wells and are currently drilling our fourth earning well. We anticipate completing all the earning wells by year-end.

We have also drilled two wells outside of the Trawick outline area, completing one of those wells in the Travis Peak. As we were drilling our earning wells on the Trawick field, two are deeper targets. We have been encouraged with excellent gas shows in the upper and middle Bossier Shale's and subsequently have moved towards completion of these intervals.

The TGU-101 well was completed in the upper Bossier Shale, testing at 3.3 million cubic foot a day at 1,800 pounds flow casing pressure and 5,200 pounds shut-in casing pressure from this vertical completion. The well is currently shut-in waiting on hookup.

As mentioned, excellent shows have occurred in the middle Bossier Shale in every one of the deep tests drilled so far. We plan to continue exploiting this resource with additional horizontal drilling in the very near future.

At County Line, the company has drilled and is producing 27 operated wells with two rigs currently working with plans to increase the rig count up to three, and possibly four rigs during the later part of this year. We continue to see exceptional results in our drilling program with an average IP between 10 million and 11 million cubic foot a day and a 30-day rate between 6 million to 7 million cubic foot a day.

Of note is the recent completion in the Katherine Von Goetz well. That well was tested over 7 million cubic foot a day with a flow casing pressure of 1,300 pounds. This is our southern most operated well on our acreage position. The well is about 7 miles south of our core area of drilling and lies on the new 12-inch pipeline recently completed. With this success, we can confidently say that the acreage which lies between the core area of drilling and this new gas well is proved and we will be developing the acreage as we move forward.

Finally at County Line, we plan to drill a vertical wildcat test to test the Bossier and Haynesville potential under our James production. This well will spud in the fall with completion expected in early winter. This well will be an important first deep data point for this area, and will be critical on our far ongoing evaluation of the Bossier Shale in this greater play area.

Again, if you are unable to keep straight, the many different initiatives that we have ongoing in our Gulf Coast region, certainly appreciate that position.

In the east, let's focus on our efforts to-date on the over pressured Marcellus play in Pennsylvania. At this point, we have approximately 135,000 acres under lease in Pennsylvania and far northwest Virginia, of this approximately a 120,000 acres lie on our Susquehanna County, Pennsylvania project. We have been working on this project since 2006 and have leased what we believe to be the core of the Marcellus play.

The Susquehanna area has the thickest and richest Marcellus we are aware of, and we believe our initial wells bear this out. To-date, we have drilled eight wells and we have three rigs operating in the project area. One of these rigs is currently drilling our first horizontal well and we will be down on this first horizontal in August. We are also utilizing smaller rigs to drill the up-hole portion of future horizontal wells, which afterwards we will move in larger rigs to complete the horizontal section.

In all, we have planned to drill 18 vertical wells, 12 horizontal wells in this play this year. This is no change from what we have previously stated. However, our completion dates have slid due to the water access issue, which we are all aware of. Also, we plan to drill up to 80 wells in this project area in 2009.

In regard to the water access issue, it has slowed our progress. However, we have worked out a short-term solution to allow us to continue the drilling pace through September when we expect to reach and receive a global water permit. Once we receive that that will allow us to increase both our drilling and completion activity into 2009 with a projected eight rig program.

We continue to hear about the lack of infrastructure, which may slowdown the development of this play. In fact, we have also heard several mid-stream gatherers that are partnering with E&P company [allied] new systems.

Cabot's approach with our history of running extensive pipeline systems in West Virginia chose to develop its own gathering system in our project area. The initial 10-mile system is being laid as we speak. We have completed some of that system and the first Marcellus production, two sales to occur in northeast Pennsylvania happened yesterday. Our first well has been hooked up to the sales pipeline and is flowing in excess of 0.5 million a day and over 2,500 pounds flow tubing pressure from a vertical completion.

We anticipate that we will have a number of wells completed and online by the end of this year and we believe we will see an exit rate of between 6 million to 9 million cubic foot per day from the Marcellus. Again, this is a nice milestone to achieve being the first to have Marcellus production in northeast PA. We have been slowed by the water access issue. Again, though we do expect to be able to receive a permit to allow us to move extensive amounts of water on to locations for completions in the very near future.

Looking into 2009, we are now buying pipeline rights-of-ways and permitting along a 57-mile pipeline expansion into this core area. The system will be ready as we drill into this area for our 2009 program. We continue to expand our opportunity base even in the face of extreme land competition and leasing competition. Lease bonus costs have sky rocketed, as we have seen bonuses in the range of $2,500 to $3,000 per acre.

Industry has ramped up activity to unprecedented levels. In short, leasing has been very difficult. However, we have been successful in gaining acreage position using our rifle shot philosophy where we lease in limited areas. We believe this will allow us to be more efficient and timely in monetizing our investment. In every case, we try to stay in close proximity to a major inner state pipeline, which allows Cabot to get our gas to sales as quickly as possible.

The company is leasing not only in our Susquehanna area, but also in several other main project areas in Pennsylvania and Warren in northern west Virginia. Evaluation of these projects new areas will commence in late 2008 and into 2009.

As most of you are aware, since our last call, we have made a $600 million acquisition. We have successfully raised the funds to pay for it. We hedged anticipated volumes in 2008, 2009 and 2010 at 13.50, 12.18 and 11.43 per Mcf, respectively. And now all that remains is to close this deal. We are working on the traditional title work as with any deal and expect the transaction to close in the middle of August. You will recall this acquisition triples our Minden acreage to approximately 37,000 acres.

Currently mentioned, we are testing the middle Bossier with our first horizontal well, which we plan to be drilled into that section. We have other opportunities and initiatives which I previously discussed.

As I said in the operation section, we are well-positioned in two of the most promising plays this industry has seen in a long time. Our task ahead is to accelerate the reserve realization in each of these areas. To do that, we have expanded capital and are putting the necessary resources in place.

I do wish we had more tangible results for all of us at this time. However, I like our position and I am confident that as we mature our opportunities, you will also appreciate Cabot's position.

If you take into consideration Cabot's acreage position, coupled with the emerging plays on our acreage, and what we found in again, on our acreage and in the immediate area, we could be on the cusp of a material growth change in our story.

If you look at the recent sell-off in the position in the market, you look at what Cabot's anticipated reserves are at year-end, we think we are trading in the ground at $2.70, $2.75 at this time. And looking at those values and certainly looking at the inflationary pressures that We have seen in the marketplace, we are looking at re-instituting our buyback program.

With that, Chasity, I will turn it back to you and open it up for any questions the group might have.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions). Your first question comes from the line of Joe Allman with JPMorgan.

Joe Allman - JPMorgan

Good morning, everybody.

Dan Dinges

Hi, Joe.

Joe Allman - JPMorgan

I guess this is for Mike or for you, Dan. In your field in East Texas, could you just talk about the presence of the upper, middle and lower Bossier and the Haynesville line?

Dan Dinges

Yes. I will make just a cursory comment, let Mike get a little more grainier on it. But for the most part, we see that Bossier section, upper Bossier down to the Haynesville in each of our three areas. I will turn it over to Mike.

Mike Walen

Thanks. Joe, It is 700 to 900 feet thick. As we drill the well, I think as Dan mentioned, we have been encountering significant gas shows with two significant pressure in the upper, what we call, the upper Bossier. The middle Bossier, which is where you have seen some of the recent announcements, what we believe is the middle Bossier.

And then, of course, in the lower Bossier, the Haynesville Shale, the folks we bought the property from actually made a completion in that interval and we also see shows in that. And of course we do not have any Bossier penetrations yet at County Line but recent drilling nearby has certainly suggested that same thing would be found at County Line. So we are pretty confident that the Bossier covers the entire acreage spread that we have in our three main projects in East Texas.

Joe Allman - JPMorgan

And when you say 700 to 900 feet thick, are you talking from the top of the upper Bossier through to the bottom of the Haynesville line?

Mike Whalen

No, that would be to the top of the Haynesville line.

Joe Allman - JPMorgan

Okay, the top of Haynesville line. Okay. So, then you got some additional with the Haynesville line?

Mike Whalen

On the Haynesville line we are seeing some really nice results on that. And as Dan mentioned, we do plan to do the horizontal test in that later on this summer.

Joe Allman - JPMorgan

Are you seeing any differences, I know you have got limited data but any differences in the quality difference between the upper, middle and lower Bossier?

Mike Whalen

In the sense of rock quality or production quality or what?

Joe Allman - JPMorgan

Both, actually.

Mike Whalen

We really do not have a lot of data yet to make that kind of definition, Joe. We just have some early time information.

Joe Allman - JPMorgan

Okay. And then, I guess the first horizontal result we will get, I know that you are doing those two horizontal wells in Minden, one to the middle Bossier, one to the Haynesville Lime and we will get the results, I guess October, November. But will we get the Minden horizontal from the acquired properties before then? And if so what is the expectation on that timetable?

Mike Whalen

It will probably be contemporaneous with that, Joe.

Joe Allman - JPMorgan

Okay, got you, Thanks. Okay, and then in your release, you are talking about net acreage in this play and then also in the Marcellus. Could you give us net acreage positions?

Mike Whalen

Well, we have a fairly high net position also. For example, the acreage that we acquired in the recent acquisition in the Minden area is 95% working interest in that position. I amAnd I am sorry, the other areas you are talking about, Joe?

Joe Allman - JPMorgan

Just, I guess, in your release you talked about 125,000 gross acreage in the Bossier play and 135,000 in the over pressured Marcellus. I amI am just trying to go from gross to net in both those plays.

Mike Whalen

In the Marcellus that is, that gross number and net number is essentially the same.

Joe Allman - JPMorgan

Okay.

Mike Whalen

Because Cabot's leasing up there 100% and there is not a great deal of division of [manual] ownership up there, simply because of the lack of historic E&P operations. And the net number is, I do not have it exactly in front of me Joe in the East Texas, North Louisiana area but it is a very high net number comparable to our gross.

Joe Allman - JPMorgan

Okay.

Dan Dinges

Joe, the majority is the acreage in County Line would be a 100%. We do have some leases where we have partners where our minimum working interest would be like 70%. In Trawick, we are right now at 100%. Our partner has not yet elected to join us on anything, so that could end up being a 100%. And up in Minden, again like County Line the majority is 100%, but we do have some leases where we have partners, but generally speaking, those never go less than about 75% working interest.

Joe Allman - JPMorgan

Got you, that is helpful. And just last one, and then I will get back in the queue. In the Marcellus Shale, I think you said you are going to get to 6 million to 9 million a day and I am thinking that is by the end of this year. Could you just help us with like, what kind of production growth do you expect to see for Cabot in the Marcellus Shale? And you can give us wide ranges, just to kind of help us to think about how this can be really meaningful for Cabot?

Dan Dinges

Great question and very good information to have. We have not as you are aware drilled our first horizontal well. All we have is kind of the sidebar information from what we have heard out there. I think one of our peers had made estimates of their horizontal completions at over 4 million cubic foot per day.

We have given pretty wide berth for us because we are still educating and learning the regulations that are a dynamic process in Pennsylvania. And so the timing of whatever the production is and when it comes on is a little bit uncertain, but we do think that the regulatory agencies are working with us, it is just that I think they are trying to determine the regulatory overprint as we go and as they anticipate a significant level of opportunity and activity up in this area.

But Joe with what we have seen, let me take this time if I may, and start it with just a vertical completion. The Marcellus, we have absolutely determined is a very nice program, if you just look at a vertical completion. The cost of drilling and completing a vertical well, what we anticipate on production and what we would anticipate on EUR yields a very very nice return project.

We think with what we have seen so far and what we have studied and what we have modeled, that our horizontal aspect to this program is going to yield the multiple enhancement that you would typically expect to see vertical to horizontal. And that would be an expectation of three to four times the IPs and the three to four times the production, I mean the reserve recognition at a cost vertical of about two times or so the cost of a vertical well.

We have not seen anything to deter us from that expectation. We expect a vertical well backing up a little bit, a vertical well to recognize a million or so a day of initial production and we would expect a vertical well to recognize over Bcf per vertical completion. So that kind of gives you a wide sideboard show, I know, but we really are anxious to get the information just as everybody else is on what we will say about the horizontal comparison.

Operator

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

Brian Singer - Goldman Sachs

Thank you, good morning.

Dan Dinges

Hi, Brian.

Brian Singer - Goldman Sachs Good morning.

With your multiple opportunities between East Texas and Appalachia, how do you think of the strategic nature of the US and Canadian Rockies assets? And whether at some point did you accounted for asset sale or whether it is just further CapEx that gets invested there alongside your other areas?

Dan Dinges

Brian, we have always looked at our diversity as opposed to a weakness a strength. We do have very good projects in the Rockies, very good projects in the Mid-Continent area. Canada, we have approached as simply a greenfield opportunity for us where it is just a very small percentage of our allocation. Certainly a valid question, because we do have not only existing project pool that is quite extensive in the East Texas, North Louisiana area, but also the Marcellus.

Looking at how we allocate capital is going to be a very extensive project for us between now and October when we submit our budget to the Board. I would say since I have been with Cabot and looking at the number of opportunities and the number of good opportunities that we have had on our plate, to be able to make these choices is as large of opportunity pool as I have seen since I have been with Cabot.

So, it is going to be a challenge, addressing your point about how much you reduce. Maybe, Canada opportunities, and you look at the overall balance of production reserves, of rate of return that the Rockies, Mid-Continent, East Texas, and the east will yield – is going to be our challenge. And I am confident that we are going to be able to put forth to the Cabot shareholder a program that is going to have a very good returns and returns on all of those metrics when we complete that process.

Brian Singer - Goldman Sachs

Thanks. I think you did make a decision just in the last, I guess few months to reduce some activity in the legacy Appalachia areas and I wondered if that was a conscious decision to prioritize the Rockies over a legacy Appalachia or if there were kind of people issues that played into that as well, as you shift capital and people into the Marcellus?

Dan Dinges

Yes. It is a little bit of both, Brian. With our staff size in the East and looking at all the moving parts that's attached to the Marcellus, trying to plough new ground not only in the field, but also through the regulatory process and being able to mature a program with some element of consistency and meeting expectations. It is taking a great deal of our manpower effort, and conscious effort to allocate away from the traditional into the Marcellus, to get a smooth flow operation, and be able to meet our, say 80 plus or minus wells expectation into 2009.

We have not allocated personnel to any great extent in between regions at this time but we certainly have our position requisitions open in the east and in East Texas, to fill some voids that we have.

Brian Singer - Goldman Sachs

Great, thanks. And lastly, you indicated you expect the water permit in the Marcellus and Northeast PA to be approved in September. Could you add any additional color and if there is any, I guess risk if that happens either earlier or later?

Dan Dinges

I will let Mike answer some of that, Brian.

Mike Whalen

Brian, as we mentioned we have approached the water issue two ways. Number one is that we have figured out a short-term solution to access water for drilling and limited completion work through the Susquehanna Basin Commission and we have got permission to do that right now. And that kinds of a stop gap measure until we get our global permit, which will be coming in about the middle of September.

And once we get that permit we have identified multiple sources of water, the permit will cover, and that permit will allow us to wrap up our drilling program, and also to get back on the completion schedules. And we think that once that is in place, the slowdown that the industry is seeing now, at least from Cabot standpoint, will be over and we will be able to get to the schedule that we had planned initially.

Brian Singer - Goldman Sachs

Great. Thank you.

Mike Walen

Okay.

Operator

Thank you. Your next question comes from the line of Ellen Hannan with Weeden & Co.

Ellen Hannan - Weeden & Co.

Good morning.

Dan Dinges

Good morning, Ellen.

Ellen Hannan - Weeden & Co.

Just a couple of question and a follow-up here. Dan, there was a time when you all had kind of looked at a $2 S&D cost overall for Cabot? And your objective of what you felt comfortable with your program. Do you still think that is still realistic in light of where costs and things are going?

Dan Dinges

Yeah, I think it is realistic. I think you are going to see some impact on that cost this year in light of our extensive leasing effort in some of the areas that we have been playing have had some fairly stellar per acre costs associated with it.

We are also as a pressure on that number, Ellen, seeing some inflationary pressures, particularly from tubulars that we will be dealing with and certainly be rolled into that number. But we do, though expect to -- we are not going to be at $2, but we expect to have a cost to defined number, I think that will be attractive in relation to the peer group.

Ellen Hannan - Weeden & Co.

Great. And then just another, in terms of the Gulf Coast area and the acquisition that you are getting ready to close, do you have any expectations for what you think you can do in terms of production growth going into 2009, just taking into consideration again constraints on pushing down of equipment and that sort of thing?

Dan Dinges

We are optimistic about our production growth, particularly considering the number of horizontal initiatives that we have ongoing right now. The difficulty on the snapshot period that we are in is just getting our hands on solid information that we can analyze, we can look at, we can do testing analysis on initial flow rates, pressures, declines to be able to make a very good forecast into 2009.

But we have seen certainly the industry and others make a robust reports on horizontal drilling and we frankly have a lot of optimism in what we are going to see but we don't have the information in hand yet. Again, frustrating for us Ellen, just like I am sure it is for you all, but know it is a little bit arm waiting right now. But we are spending money and we have rigs committed to this horizontal section and we are going to get the information between now and the end of year on a whole lot of new projects.

Ellen Hannan - Weeden & Co.

That's terrific. Thanks. And I just had one other question maybe for Mike. Could you just give us an idea of what your expectations are on a horizontal Haynesville Lime well, maybe in contrast with maybe James Lime or the Haynesville Shale. What are you looking for in terms of -- what do you expect out of that horizontal test?

Mike Walen

Well, we're based on modeling, Ellen, on results of our vertical wells. And we certainly don't think that we will see any difference in multiples between vertical to horizontal as what we have talked about earlier in the James, as well as in some of these shale plays. So it will be a multiple three to four times what we see on vertical for the reserves.

And right now the best we are ranging up to 1 to 1.5 Bcf of reserves on the vertical well in the Haynesville. I am thinking that on a horizontal lime shot, should see three or four times multiples.

Ellen Hannan - Weeden & Co.

That's it for me. Thank you very much.

Dan Dinges

Thank you.

Operator

Thank you. Your next question comes from the line of Eric Hagen with Merrill Lynch.

Eric Hagen - Merrill Lynch

Hi, good morning.

Dan Dinges

Hi, Eric.

Eric Hagen - Merrill Lynch

Two question on any problems acquiring rigs? And also pipe getting tubulars, have you pre-purchased that?

Dan Dinges

As far as problems acquiring rigs, as you know, that there is a number of new bills going on out there. And so, depending on what area in particular you are talking about, but in the hot areas certainly we have rigs in place and there are a couple of areas in our key play areas that we are looking for additional rigs. In pipe we have, and we continue though to look forward to securing additional pipe for our 2009 program. I'll let Mike add a little color if he would like.

Mike Walen

Yeah, Eric. We do have our inventory for tubulars pretty much purchased and in inventory. And we have made a habit of whenever we run across tubulars, that we can acquire, we do buy that pipe and put it again in inventory. And as far as rigs go, we are actively looking for rigs right now to expand our program, especially in East Texas. And as we are able to, we will add-on additional capacity on that front.

Eric Hagen - Merrill Lynch

Are you seeing pressure in day rates out there, is it significant or --?

Mike Walen

We are seeing increases pretty much across the board on our operating costs.

Eric Hagen - Merrill Lynch

Okay. And the last one just on Marcellus to get some clarification. So, the global permit, does that cover sourcing and disposal? And what are some of your options for disposing of water? You have to treat it --

Mike Walen

Eric, that permit covers sourcing of water. We have already lined up disposal facilities that we are currently using that will be able to take care of our needs in the short to medium-term. That's an issue that industry is addressing as a group with the state agencies as we speak. And I don't anticipate any issues with that going forward.

We are actually using a lot of our frac waters again. We are filtering those waters and using those in subsequent completions. So it is just something that we have to work through and to do our planning. The access of water in my mind was the big issue. I think we have that solved. The disposal, there is already facilities available and we are accessing those now.

Eric Hagen - Merrill Lynch

And Mike, I got just one on the Paradox, the well you are completing there, is that a shale? Is that one of the salt flank type well or is it similar to what Williams and Barrett are chasing out there?

Mike Walen

No, no, no. This well is based on a 3D controlled very large structural feature, not as large, but analogous to the (inaudible) field and we are testing the Leadville carbonates.

Eric Hagen - Merrill Lynch

Okay. So, it is a more conventional play. Okay, great. Thanks. I appreciate it.

Dan Dinges

Thanks, Eric.

Operator

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

Andrew Coleman - UBS

Good morning, folks.

Dan Dinges

Good morning.

Andrew Coleman - UBS

Yeah, I had a question on your reserve booking philosophy. You still are thinking 300% reserve replacement or more is going to be possible with this increased capital budget?

Dan Dinges

Yes, we are actually thinking higher than that, Andrew.

Andrew Coleman - UBS

Maybe you can give us a sense as to what level that might?

Dan Dinges

It cannot get anymore great than that but it certainly going to be north of 300%.

Andrew Coleman - UBS

Okay, great. And then, is it also fair to think about philosophically that when you are drilling in some newer areas, as you are seeing in Northeast Pennsylvania and perhaps, some of your newer Haynesville tests and Bossier tests that you will be able to book more than one PUD for one proved location or are we still in such an early phase of proving up that the wells will deliver that, there will be a little constraint to get some well results?

Dan Dinges

I would say that traditional with our character that by year-end with the limited information that we are going to have, although we are going to have significantly more information than we have today, that we will not be real aggressive on PUD bookings until we see extended production tests out of some of these initiatives.

So to answer your question more succinctly, we don't know how extensive PUD booking we can recognize, but I would say that whatever opportunities are out there that we are going to take the conservative approach initially.

Andrew Coleman - UBS

Okay, great. Thanks. Just a clarification on the comment made earlier about the 1 to 1.5 Bcf you are for the vertical Haynesville and about three to four times that for a horizontal. If I heard that correctly that then implies about a 3 to 6 Bcf for horizontal which is a bit below what some competitors have put out there?

Dan Dinges

I am not talking about Haynesville Shale; we are talking about the Haynesville Limestone here.

Andrew Coleman - UBS

Okay.

Dan Dinges

Okay. But the number is correct for the lime.

Andrew Coleman - UBS

Okay, perfect. And then, lastly, just kind of a question looking at Canada again. Did you guys have anything, Hinton and that is located relative to some of the Canadian shale places that are emerging. Have you guys looked at any potential up there?

Dan Dinges

We have. In fact, our drilling at our Hinton area, we have recognized maybe some shallow shale opportunities. But, Mike do you want to comment on it?

Mike Walen

Our Hinton play is quite a bit south and east of the Montney Play in Northwest BC, and obviously, way south and east of the other shale play up in northeastern BC. But we are looking at projects in the Montney Play to exploit shale. Cabot does have a small position in that play. And of course, as Dan said, we have encountered excellent gas shows in our drilling in the Hinton area for the shallower shale. So we are going to be probably trying at least one completion in a shale later on this summer, and we will just see how that works out as we go forward.

Andrew Coleman - UBS

Okay. Thank you. And if I could squeeze one last question in. On the hedging front, it looks like you guys are about 70% hedged this year and about a little over half-hedged next year. Is there a bit of a macro call there for you guys or is it just kind of a better course of business?

Scott Schroeder

That is a normal course of business, Andrew. What we try to do is traditionally we layer in as we see strength in the market and we were doing that over the course of a longer period of time. Clearly, when we started 2008 there was a lot more weakness than any of us ever anticipated versus what has actually transpired thus far in 2008, so we even added to the 2008 position during the first quarter. The latest wedge that we added was to protect the acquisition, which we laid out in the June conference call related to the acquisition where we did some straight swaps. And right now we are kind of on the sidelines just evaluating if we want to layer anymore into 2009 and look out into 2010, but right now the hedging committee is taking the posture to just wait and see.

Andrew Coleman - UBS

Okay. Thank you for your time today guys.

Dan Dinges

Thanks, Andrew.

Operator

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

Jack Aydin - KeyBanc Capital

Hi, guys.

Dan Dinges

Good morning, Jack.

Jack Aydin - KeyBanc Capital

Couple of questions, Dan and Mike and Scott. Mike, could you update us on what is happening in the hurricane and more directly what is happening in the Huron Shale, what you are doing there? And second question to that, your competitors have been talking about [Debria] play more than ever. Can you give us a little bit more insight to what you are thinking?

Dan Hinges

Yeah, Jack, I will just make a quick comment on the hurricane and the Huron as far as just allocation of resources. We have slowed that to a crawl, simply because we are trying to get ahead of the curve on the Marcellus, with our resources that are available to us at this time and prior to us being able to add new people. As far as the opportunity in the Huron and Debria, I will turn it over to Mike.

Mike Walen

First of all Jack, we continued to drill vertical Huron wells just as a matter of business up there in West Virginia. We are also looking and hope to get it drilled later on this summer, early fall, a multiple leg horizontal well in the Huron, in the hurricane area. And this would be, lets say, kind of a like a pitchfork type design, where we can cross a lot of natural faulting and get the natural flows and attempt to make a natural completion rather than injecting all this nitrogen that we have in the past. So that is another new initiative that we are looking at.

Also, we are very aware of Debria and the play in the Debria in the western part of West Virginia. And the guys in Charleston are right now planning a horizontal well in Debria one of our leases in the western West Virginia to see what kind of results we can get out of the Debria. This well is being drilled not too far away where some of our competitors have announced some good Debria success.

Jack Aydin - KeyBanc Capital

Okay. Dan, you mentioned that on the vertical wells that IP million Bcfe -- are we talking about a cost. What kind, you didn't give us the cost of the well. What are we talking about per well cost?

Dan Dinges

On a vertical well, Marcellus completed well costs were $1 million to $1.2 million.

Jack Aydin - KeyBanc Capital

Okay. Scott, corporate taxes going forward. What kind of rates should we use? 36, 37?

Scott Schroeder

The provision should stay right around 37, 38. The deferral, we deferred more in the second quarter. We still think we are going to be in the 75% to 85% range when you look at the full year. You might trend more to the higher end of that range, more towards the 85% based on what we are seeing right now, but we just didn't want to fundamentally change it till we got more confidence than that.

Jack Aydin - KeyBanc Capital

Dan, I mean you have got asset base in everything booked in the Marcellus in East Texas. Do you have the people really to push this program, accelerate the program, and if you don't, what are you guys doing about it to get this going because the competition is really strong and everybody moving fast?

Dan Dinges

Yes.

Jack Aydin - KeyBanc Capital

So what are you trying to do or what are you going to do to move this thing a little bit faster?

Dan Dinges

Of course Jack, our business has always been extremely competitive and these new plays, the level of intensity certainly seems to escalate. We are looking to place and hire some new people. We are doing some internal shuffle of our organization. That is not big and different, but certainly we are looking at how we can do more program planning and have specific people in charge of only those areas. For example, right now in the east, we have all of our people up there still looking not only at the Marcellus but their responsibilities are also in the traditional areas.

We have talked about in looking at and structuring the idea of having a more intense focus of people only allocated to the Marcellus. So the distraction would not occur in their traditional areas. The same I think is going to hold true in the east, Jack, as we get more information from these new initiatives and it looks like the ramp-up in the horizontal drilling occurs in East Texas, though we have some that are allocated exclusively there. We have some that are cross pollinated really from South Texas to East Texas but I would say that shift is going to occur with an exclusive focus where the majority of the capital are going and that is in East Texas.

So, we are trying to do all of the above and I feel confident that we are going to be successful in finding some additional key people that we are going to also restructure a little bit internally in each of the regions to focus more intently on where we are going to be allocating the capital. I think we can compete with anybody out there, Jack.

Jack Aydin - KeyBanc Capital

Thank you.

Operator

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

Larry Busnardo - Tristone Capital

Hi, good morning.

Dan Dinges

Hi, Larry

Larry Busnardo - Tristone Capital

A little bit of clarification just on the drilling process in the Marcellus on the horizontal well. As you are drilling, you are using two rigs right now, smaller rig and then a larger rig. Is that how it is going to be going forward or is that process going to change as you get new rigs into the play?

Mike Walen

Larry, this is Mike. That process would change as we get more larger rigs in the play. Right now we have two rigs in the field capable of drilling horizontals. We have a third rig that is really, it kind of goes to its limit to go horizontal. So we are using that rig just as to drill the up-hole portion of these horizontal wells, set our intermediate and then come back with a larger rig. But I think as we get into '09, you are going to see that we are going to have larger rigs in place to drill the horizontal wells from the grassroots and we may be using the smaller rig to drill vertical wells in areas where we cannot drill a horizontal well.

Larry Busnardo - Tristone Capital

Okay, great. And just to reconcile back on the capital budget. I guess the only increase in terms of the leasehold is that, only $55 million. Is the rest of that going towards drilling and, I guess infrastructure?

Dan Dinges

That's correct, Larry.

Larry Busnardo - Tristone Capital

Okay. And then Scott, just one more just on the stock-based comp. How do you envision that going forward? I know that is going to be a function of share price, but just as it relates to non-execs?

Scott Schroeder

Non-execs; there was a meeting and discussion about it at the Board level on Thursday. It is being evaluated with the intent of putting potentially another plan in place with higher targets for the employees because of a lot of the personnel issues we are talking about here. The original intent was for retention and incentive. Clearly, nobody anticipated the level of stock movement across this entire industry in the first five months of that plan. Clearly, the plan originally had a 3.5 year term on it, and the fact that it reached payout in five months highlights just how aggressive the market was in this first part of the year.

We are evaluating it and at some point in time, we will probably look to roll something out again for the employees. Again, the officers would not participate, but we are constrained on the employee side like everybody else.

Larry Busnardo - Tristone Capital

Okay. All right, great. Thanks a lot.

Dan Dinges

Thanks, Larry.

Operator

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

Joe Allman - JPMorgan

Yeah, thanks again. In terms of the CapEx budget, that moved up from 560 to 750. Could you break it up by how much of that is because of the acquisition? And how much of that just roughly is, just because you are getting more aggressive in your drilling, and you drill more and acquiring more?

Scott Schroeder

As Larry just asked, it is the lease-back and the drilling, no money included in the 750 relates to the acquisition.

Joe Allman - JPMorgan

Okay.

Scott Schroeder

The acquisition will be a layer on top of that.

Joe Allman - JPMorgan

Got it, okay. And how much of that would you estimate?

Scott Schroeder

The acquisition?

Joe Allman - JPMorgan

No, how much additional CapEx? I guess, I am trying to figure like --

Scott Schroeder

The whole 750 versus 560, the 190 is all CapEx.

Joe Allman - JPMorgan

I don't understand. I guess, like how much given that kind of the activity and the money that is being spent there now, like your 560 does not include spending between the end of August and December 31st on the acquired properties, right? So I am trying to figure out like how much of this incremental 190 is just getting more aggressive on your legacy properties and just buying more acreage? If you can break them, maybe you are not thinking that way but --

Scott Schroeder

Hold on a minute, Joe.

Joe Allman - JPMorgan

Sure.

Scott Schroeder

What the acquisition does is the 750 includes no activity related to the acquisition. The acquisition is $603 million. On top of that there is about a $50 million to $60 million level of capital that we are assuming during the course of the rest of the year for the four rigs running.

Joe Allman - JPMorgan

Okay. And that is not in the 750?

Scott Schroeder

That is not in the 750. The 750 number we updated was just based Cabot. The acquisition has not happened yet. We have not added anything in for that.

Joe Allman - JPMorgan

Understand. So, if we are modeling the acquisition, maybe a better number would be like 800 or 810 or something, is that?

Scott Schroeder

Yes.

Joe Allman - JPMorgan

Okay. For the full-year? Okay.

Scott Schroeder

For the activity related to the acquisition, yes.

Joe Allman - JPMorgan

Got you. Okay. All right, that's good. And then just back to an earlier issue. Like just constraints in Marcellus clearly, the global water permit is going to help and you have got kind of short to mid-term disposal solutions. Are there other constraints that you are worried about in the Marcellus? And any other constraints you are concerned about in the Bossier Shale, Haynesville play?

Mike Walen

Marcellus, no, not really. I think we have the rigs in place to do what we need to do. The frac crews are in place. We two groups in place. And in the Bossier, Haynesville same story, we are looking for additional rigs to ramp-up a little activity. But other than that, we are in good shape for tubulars permit as well as the people and rigs in the field.

Joe Allman - JPMorgan

Got you. And Mike, in terms of I asked the question about the Bossier intervals, but just qualitatively, like what is the difference between the Haynesville Lime and the Bossier Shale in terms of what you know with the productivity and the reserve recovery you can get? Can you just talk about that qualitatively?

Mike Walen

Well, from Cabot's point of view, we just don't have a lot of data yet from the Bossier Shale. We have some initial test data. None of these wells are yet hooked up and flowing, so we are not quite sure what they are going to do. They looked good on the outside here looking in, but we are going to have to have some time. Of course, we have some good history in the Haynesville Lime up at Minden from the vertical sense, and those wells look pretty strong. And now we are hoping that the horizontal lags will give us multiples of production and reserves, Joe. But I'd say in the shale, it is too early to say. And the limestone, the vertical sense looks good and we will wait and see what the horizontal well does.

Joe Allman - JPMorgan

Got you, okay. And then Mike, also, in terms of the costs you are seeing, you said across the board you are seeing costs increases. For what kind of level, I mean, what kind of percentage increase are you seeing versus the same time last year, whatever kind of starting point?

Mike Walen

We have seen increases in rig rates; in certain areas we have seen increases in tubulars. We have seen actually in frac services, in cementing services to menu services actually flat to a little bit of an increase. But there is definitely upward pressure on services in East Texas, and up in Appalachia based just on the level of activities that we are seeing.

Joe Allman - JPMorgan

Okay. And then I guess, Scott, maybe you guys made this clear but maybe I missed it. I think LOE was higher than what you guys had guided in the second quarter. Could you just comment on that what were the reasons for that?

Scott Schroeder

It was a lot of issues based on operations, lease maintenance, subsurface maintenance. There was additional work over, expense work over activity. There was treatment of some wells, primarily in the east, and then the biggest piece of the component was fuel cost. I don't think anybody anticipated when we did the original budget or even the original guidance off the original budget, where just fundamental gas prices go. Keep in mind we have about 100 plus employees driving trucks up and down the roads of West Virginia checking on our 3,000 wells. So, that was over a $1 million of incremental fuel costs above our budget.

Joe Allman - JPMorgan

Got you. Okay. All right, very helpful. Thanks, everybody.

Dan Dinges

Thank you, Joe.

Operator

Thank you. Your next question comes from the line of Sarah Spencer with Quartz.

Sarah Spencer - Quartz

Hi. Just wanted to check something. In the Marcellus, when you said you were reusing water, Mike, does that mean you are recycling? And are there recycling facilities in the Marcellus yet? Also, where are the disposal wells up there? Where do they tend to be clustered?

Mike Walen

On the recycling, we are on limited basis, it is just not a big deal. Cabot is attempting to, or we are recovering water that we frac with, and we are filtering that ourselves before we put it back into the frac tanks. So there is no plant that we go to. On the disposal well, the nearest disposal well that we are using is just across the border in New York State, and that is a permitted disposal well and that is where we take our waters.

Sarah Spencer - Quartz

Okay. Thank you.

Operator

Thank you. Your next question comes from the line of Larry Benedetto with Howard Weil.

Larry Benedetto - Howard Weil

Thank you.

Dan Dinges

Hi, Larry.

Larry Benedetto - Howard Weil

Dan, I was wondering if you could give us a little bit more color on the horizontal well into the Lewis Shale?

Dan Dinges

Larry, this will be our first attempt. I will flip it on over to Mike also on that.

Mike Walen

Larry, we are drilling a lot of wells in this field, vertical wells. It is an Almond field and as we drill down to it, we see very thick peers to be over pressured shale with a lot of big shows in it. And we thought that if we put a horizontal leg in the shale, we might find something interesting. And so that really is the background of it. We had tried a couple of vertical completions in it and we have got some gas out of it that we are actually selling, not at big rates, but we are thinking that a long lateral with a good frac could give us pretty good pop there.

Larry Benedetto - Howard Weil

And Mike, anticipated well cost?

Mike Walen

Larry, I just do not want to guess at that. I can get back with you.

Larry Benedetto - Howard Weil

Okay. That is fine.

Mike Walen

All right.

Larry Benedetto - Howard Weil

And then, Dan, last year we had pretty wide differential in the Rockies. You re-allocated some capital away from the Rockies into other areas. We are starting to see the wider differential back with us now and it may stay with us for some time. Any thoughts on re-allocation of capital if it does turn out to be, we are in a much wider differential for another year, year and a half or so?

Dan Dinges

Yeah, if it does stay fairly wide in the net back to us, Larry, or not the range that we want them to be, you have kind of made a list as we have of the number of different opportunities that we are looking at in East Texas, and certainly trying to ramp the Marcellus. But, we certainly will have enough places to re-allocate capital in that, Larry, if I look at the biggest charge that I have between now and October and not just me but all of us have between now and October is to make that decision, make that call on the percentage of allocation of capital to each of our operating areas.

Again, as I reference it as high class problem because we have a lot of opportunity but it is going to be a challenge to put together the best program with the best metric results. So, yes, we are looking at it actually succinctly and if it does blow out, we are obviously going to slowdown capital in that area.

Mike Walen

Larry?

Larry Benedetto - Howard Weil

Yes.

Mike Walen

I looked at in my notes here and that Lewis horizontal is going to be, dry hole cost is going to float around a couple of million bucks and completed cost depends on how many fracs we put on it, maybe up around $3 million.

Larry Benedetto - Howard Weil

Great. Thanks a lot.

Mike Walen

Okay.

Operator

Thank you. There are no further questions at this time.

Dan Dinges

Okay, Chasity. I again appreciate everybody's support and beg a little bit for your patience as we work through our initiatives, all the things that we have mentioned in this teleconference. I think everybody has a sense that there could be significant opportunity in what we are doing, we certainly do.

We do look forward to being able to report back at our next meeting with some clean information, if you will. And maybe a little bit more direction where our program is going to go. Again, appreciate all the support. And look at this downturn in the market as an opportunity. Thank you.

Operator

Thank you for joining today's Cabot Oil & Gas second quarter 2008 conference call. You may now disconnect.

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Source: Cabot Oil & Gas Corp. Q2 2008 Earnings Call Transcript
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