Coterra Energy Inc (CTRA) 2008 Q2 法說會逐字稿

Good morning. I will be your conference operator today. At this time I would like to welcome everyone to the Cabot Oil & Gas Corporation 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.

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

The forward looking statements and language 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 operational update with some recent operational successes and our current efforts in the Marcellus and Bossier, which I will expand on later in our discussion. Financially the Company reported an excellent second quarter with approximately $70 million of net income after removing with the expenses associated with stock compensation that is driven by FAS 123R valuations. This does represent second quarter record 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 nonofficer employees. This reduced cash flow per share about $0.14. The stock compensation expense relates to the finalization of a nonofficer 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 nonofficer group was $15.7 million pretax.

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 continued to allocate resources away interest 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 ENP operations of any magnitude. The Gulf Coast met expectations, but more importantly, it is positioned to increase base volumes and we will also see the additions of the acquired volumes from 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 we are currently drilling that we 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 in the East to our Marcellus expansion in Pennsylvania and also expanding our east Texas Bossier effort. Clearly, this will impact production volumes from each area. However, this shift to capital will increase the Company's production overall as we move forward. It's going to be just a matter of what volumes, quantity of volumes come from which area.

For the third and fourth quarter our 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 our redirect of resources and also to the regulatory delays relating to water. However, we did reach a milestone yesterday with the industries first Marcellus production flowing to cells in Northeast PA. I'll 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 extensive land grab that industry is experiencing right now, plus the additional drilling opportunity. 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 granular discussing each region. In the West, through the first half of the year, Cabot has drilled 61 gross wells 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 find 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-continental and Rockies drilling program and we do expect this level of success to continue into 2009.

On the expiration front we have finished drilling the South [Gypsum] Wildcat we have talked about several times. We are delayed in drilling this well with the drilling stipulations, but we have reached total depth. Production casing was set over the Leadville interval 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 the paradox. We will spud the Abbey Wildcat. This 9,000 foot 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 bill 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 7,000 acres in the field. Cabot will have a working interest of 45% to 80% or so in this 7,000-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 Countyline the first half of the year which brings a total of 27 horizontal James wells in the field. Now, we also have drilled seven [Treywick] wells. Four of those are outsided 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 drilled -- 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 Countyline, a rig in [Treywick] and a rig working in Mississippi. We will also add two rigs later this year, or this summer, I should say, into our Countyline 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 and an August response to the new opportunities we see associated with the Bossier Hainesville shell play. We have approximately 135,000 acres in this play in both states. While our three main projects fall within the play fairway. Competitor activity as well as Cabot's work has demonstrated the shale potential in this area.

As I mentioned at Minden, we are currently drilling a middle Bossier horizontal test. This well will reach depth in ten days. It is testing a zone equivalent to that by an operator in Harrison County, recently. So far in drilling this well, we have incurred encouraging gas shows while drilling. Additionally in Minden, we will also exploit the recent success of a vertical well in the lower Bossier, i.e. Hainesville shell. And middle Bossier, drilled by the properties we are acquiring. The well that they drilled testing both zones and 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 Hainesville line 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 Bcfe of 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 Hainesville line immediately following our Bossier horizontal test that we are 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 an spud this well after completion of the Bossier well. Both well bores will be completed back-to-back and we anticipate completion of the first production in October.

The recently acquired properties at Minden to be exploited with a four-rig drilling program 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 Hainesville and Bossier shale potential. We view these properties to have significant resource opportunities in these zones. We certainly would be ocreated to this acquisition.

At [Treywick] we continue our one well drilling program. Obviously as I've mentioned we are restricted to one rig as we are targeted to drill moving towards drilling eight earning wells, most being planned to the horizontal -- to the Hainesville. 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 [Treywick] outline area completing one of those wells in the Travis Peak. As we were drilling our earning wells -- on the [Treywick] field to our deeper targets we have been encouraged with excellent gas slows in the upper and middle Bossier shales and subsequently have moved to 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 location 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 shales and 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 Countyline, 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 latter part of this year. We continue to see exceptional results in our drilling program, with the average IP between 10 and 11 million cubic feet a day and a 30-day rate between 6 to 7 million cubic feet a day. Of note is the recent completion in the [Katherine Van Ghet] well. That well was tested over 7 million cubic feet 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 Countyline, we plan to drill a vertical Wildcat test, to test the Bossier and Hainesville potential, under the James production. This well will spud in the fall with completion expected in early winter. This well will be an important first deep down a point for this area and will be critical on our ongoing evaluation of the Bossier shale in this greater play area. Again, if you're unable to keep straight the many different initiatives that we have ongoing in our Gulf Coast region, I can certainly appreciate that position.

In the East, let's focus on our efforts to date on the overpressured Marcellus play in Pennsylvania. At this point, we have approximately 135,000 acres under lease in Pennsylvania and far northwest Virginia. Of this approximately 120,000 acres lie on our [Susquhana] 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 [Susquhana] 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 fist 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 plan 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 slow down the development of this play. In fact, we have also heard several mid-stream gatherers that are partnering with ENP company 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 and the first Marcellus production two sales to occur happened yesterday. Our first well has been hooked up to the sales pipeline and is flowing in excess of 0.5 a million a day and over 2500 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 a 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 to locations for completions in the very near future.

Looking into 2009, we are now buying pipeline right-aways and permitting along a 57-mile pipeline 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 costs have sky rocketed as we have seen bonuses in the range of $2,500 to $3,000 per acre. The industry has ramped up activity to unprecedented levels. In short, leasing has been difficult, however, we have been successful in gaining acreage positions, using our riffle-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 interstate pipeline, which allows Cabot to get our gas to sales as quickly as possible. The Company is leasing not only in our [Susquhana] area, but also in several other main project areas in Pennsylvania and one in northern West Virginia. The evaluation of this projects in new areas will commit 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 volumes in 2008, 2009, and 2010 at 1350, 1218 and 1143 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, 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'm 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 merging plays on our acreage, and what we found in the -- 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 selloff in the position in the market and you look at what Cabot's anticipating 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 looking at the inflationary pressures that we have seen in the marketplace we are looking at reinstituting our are buy back program.

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

(OPERATOR INSTRUCTIONS) Your first question comes from the line of Joe Allman of JP Morgan.

Good morning, everybody.

Hi, Joe.

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

Yes. I will make just a cursory comment get Mike get a little more granular on it. For the most part we see that Bossier section, upper Bossier down to the Hainesville in each of our three areas. I'll turn it over to Mike.

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 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 then the lower Bossier, the AKA, the Hainesville shale. The folks we bought the property from actually made a completion in that interval. We also see shows in that. And of course we don't have any Bossier penetrations yet at Countyline but recent drilling nearby has certainly suggested that same thing would be found at Countyline. So we are pretty confident the Bossier covers the entire acreage spread we in our three main projects in east Texas.

When you say 700 to 900 feet thick, are you talking from the upper Bossier through to the bottom of the Hainesville line?

No, to the top of Hainesville line.

Okay, to the top of the Hainesville line. Then you've got some additions.

On the Hainesville line we are seeing some good results on that. As Dan mentioned, we are do plan to do the horizontal test in that later on in the summer.

Are you seeing any differences? Any difference -- a quality difference between the upper, middle or lower Bossier areas?

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

Both actually.

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

Okay. And then the first horizontal result we will get. I know you are doing those two horizontal wells in Minden. One to middle Bossier, one to the Hainesville line. 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's the expectation on that timetable?

It will probably be contemporaneous with that, Joe.

Thank you. In your release, you're talking about net acreage in this play and then also in the Marcellus. Could you give us -- could you give us net acreage positions?

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'm sorry, the other areas you are talking about, Joe?

Just I guess to know in your release you talked about 125,000 gross acres in the Bossier play and 135,000 in the overpressured Marcellus. I'm just trying to go from gross to net in both those plays.

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

Okay.

Because Cabot's leasing up there 100% and there is not a great deal of division of mental ownership up there simply because of the lack of historic ENP operations. In the net number, I don't 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.

Okay.

Joe, in the majority of the acreage in Countyline would be 100%. We do have some leases where we have partners where our minimum working interest would be 70%. In [Treywick] we are right now at 100%. Our partner has not yet elected to join us on anything so that could end up being 100%. And up in Minden, again like Countyline 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.

That's helpful. Last one then I will get back into queue. In the Marcellus shale you said 6 to 9 million a day and I'm thinking that's -- by the ends of this year. Could you just help us with what kind of production growth do you expect to see for Cabot in the Marcellus shale and just even give us wide ranges just to kind of help us think about how this can be really meaningful for Cabot.

Great question. And very good information to have. We have not as you're aware drilled our first horizontal well. All we have is kind of a side bar 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 birth for us because we are still educating and learning the regulations that are a dynamic process in Pennsylvania. 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. This is at a cost vertical of about two times the cost or so of a vertical well. We have not see 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 Bcfe per vertical. That gives you a wide sideboard show. We are just as anxious to get the information just as everybody else is on what we will say about the horizontal comparison.

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

Good morning.

Hi, Brian.

With your multiple activities between east Texas and Appalachia, how do you think of the strategic nature of the US and Canadian Rockies assets and whether at some time they get or whether it is cap-Ex that gets invested alongside your other areas?

Brian, we have always looked at our diversity as opposed to a weakness a strength. We do have very good projects and in the Rockies very good projects in the mid-continent area. Canada, we have approached as simply a green field opportunity for us, where its just a very small percentage of our allocation. Certainly a valid question, because we do have not only an 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 from -- since I have been with Cabot and looking at the number of opportunities and the number of good opportunities that we've had on our plate to be able to make these choices is as large of an opportunity 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'm confident that we are going to be able to put forth to the Cabot shareholder a program that's going to have a very good returns and returns on all those metrics when we complete that process.

Thanks. I think you did make a decision just in the last 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 Legacy Appalachia or if there were kind of people issues that played into that as well as you shift people and capital into the Marcellus.

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 plow 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, 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 well expectation into 2009. We have not allocated personnel to any great extent in between regions at this time but we certainly have position requisitions open in the East and in east Texas to fill some voids that we have.

Great. Thanks. Lastly, you indicated you expect the permit in the -- the water permit in the Marcellus and northeast PA to be approved in September. Can you add any color or if there is any risk that happens either earlier or later?

I will let Mike answer some of that, Brian.

Brian, as we mentioned we have kind of 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 [Susquhana] basin and we have got permission to do that now. That's kinds of a stop gap measure until we get our global permit which will be coming in the middle of September. Once we get that permit, we have identified multiple sources of water that the permit will cover and that will be able -- that permit will allow us to wrap up our drilling program and also get back on the completion schedules. And we think that once that's in place and the slow down that the industry is seeing now, at least from Cabot standpoint will be over and we we will be able to get to the schedule that we had planned initially.

Great. Thank you.

Thank you. Your next question comes from the line of Ellen Hannan with Weeden and Company.

Dan, there was a time you all had kind of looked at a $2 S&D cost overall for Cabot. What you felt comfortable with your program. Do you still think that is real stick in light of where costs and things are going?

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 -- might not be at $2 but we expect to have a cost to find number that I think will be attractive in relation to the peer group.

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

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 on initial flow rates, pressures, declines to be able to make a 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'm sure it is for y'all. But, it is a little bit waiting 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.

That's terrific. Thanks. One other question maybe for Mike. Could you just give us an idea of what your expectations are on a horizontal Hainesville line well maybe contrast it with James Line. What are you looking for? What do you expect out of that horizontal test?

We are based on modeling, Ellen, on the results of our vertical wells and we certainly don't think that we will see any difference in multiples between vertical to horizontal as to 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 -- we are ranging 1B to 1.5 Bs reserves in Hainesville. I'm thinking a horizontal line shot should see three or four times multiples.

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

Thank you.

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

Good morning. Just a question on any problems acquiring rigs? And also pipe getting tubulars? Have you prepurchased that?

As far as problems acquiring rigs, as you know there is a number of new bills going on out there and depending on what area in particular you're 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 and 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 you would like.

Yes, Eric. We do have our inventory for tubulars pretty much purchased and in inventory and we have made a habit of when ever we run across tubulars that we can acquire we do buy that pipe and put it 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 we will, as we are able to, we will add-on additional capacity on that front.

Are you seeing pressure in day rates out there? Is it significant?

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

Okay. And the last one was just the 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?

That permit recovers 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.

Got you. One on the paradox, the well you're completing there, is that a shale? Is that one -- is that a assault flank type well or is it similar to what Williams and Barrett are chasing out there?

No, 3D very large controlled structure feature. Not as large but analagous to the Elizabeth field, and we are testing the leadville carbonates.

So it is a more conventional play. Okay. Great. Thanks. Appreciate it.

Thank you, Eric.

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

Good morning, folks.

Good morning.

Had a question on your reserve booking philosophy. Are you still thinking 300% reserve replacement or more will be possible with this increased capital budget?

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

Maybe you can give us a sense of what level that may be?

I can't get any more granular than that, but it is certainly going to be north of 300%.

Great. 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 Hainesville tests and Bossier tests. That you will be able to book more than one pud for one approved location or is it still such an early place approving of the wells that you will be a little constrained so you will get some resolved?

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 booking 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.

All right. Great. Just a clarification on the comment made earlier about the 1 Bcfe to 1.5 Bcfe for the Hainesville vertical and about 3 to 4 times that for a horizontal. If I heard that correctly that then implies about a 3 Bcfe to 6 Bcfe for horizontal which is a bit below what some competitors have put out there.

I'm not talking about Hainesville shale, we are talking about the Hainesville limestone here.

Okay.

But the number is connect for the line.

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

We have. In fact, our drilling in the Hinton area, we have recognized maybe some shallow shale opportunities. Mike, do you want to expand?

Our Hinton play is quite a bit south and east of the Motney in BC and way south and east of the other shale play up to north eastern BC. But we are looking at projects in the Motney play to export shale. Cabot does have a small position in that play. Of course as Dan said, we have encountered gas shows in our drilling in the Hinton area for the shallower shales. 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.

Okay. Thank you. 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 bit of a macro call there for you guys or is it a better course of business?

That's 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 any more into 2009 and look out into 2010. But right now the hedging committee is taking the posture to just wait and see.

Okay. Thank you for your time today, guys.

Thanks, Andrew.

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

Good morning, guys.

Good morning, Jack.

Couple of questions, Dan, Mike and Scott. Mike, could you update us on what is happening in the hurricane and more directly what's happening in the shale, and you're doing there. And second question to that, your competitors are talking about the Huron play more than ever. Can you give us a little bit more insight into what you're thinking.

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 on 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 the Boria, I will turn it over to Mike.

First of all, we continued to drill vertical here on wells just as a matter of business up there in West Virginia. We are also looking and hope to get it drilled late summer, early fall, a multiple leg horizontal well in the Huron, in the hurricane area. This will be sort of like a pitch fork 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's another new initiative that we are looking at. Also, we are very aware of Boria and the play in the Boria in the western part of West Virginia. And the guys are now planning a horizontal well in one of our leases in western West Virginia to see what kind of results we can get out of the Boria. This well is being drilled not too far away where some of our competitors have announced some good Boria success.

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

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

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

The provision should stay right around 37, 38. The deferral, we deferred more in the sec quarter. We still think we will 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 until we got more confidence in that.

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

Yes.

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

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 an hire some new people. We are doing some internal shuffle of our organization that is not big, indifferent, 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 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, that 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's in east Texas.

So we are trying to do all of the above and I feel confident that we are going to be successful and finding some additional key people that we are going to also restructure a little bit internally 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.

Thank you.

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

Good morning. A little bit of clarification, just on the drilling process in the Marcellus on the horizontal wells. You are using two rigs right now, smaller an larger rig. Is that how it will be going forward or is that process going to change as you get more rigs into the play?

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 to drill the uphole portion of these horizontal wells. Set our intermediate and come back in with a larger rig. In 2009 you will see we will have larger rigs in place to drying the horizontal wells from grass roosts and we may be using the smaller rig to drill vertical wells in areas where we we cannot drill a horizontal as well.

Great. Just to reconcile back on the capital budget. With the increase -- I guess the only increase in terms of the leasehold is that only $55 million? Is the rest going towards drilling an infrastructure?

That's correct, Larry.

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

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 much 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 ultimately 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.

Okay. Great. Thanks a lot.

Thank you, Larry.

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

Thanks again. In terms of the cap-ex budget, that moved up from 560 yo 750, could you break it up? How much of that is because of the acquisition and how much of that just roughly is just because you're getting more aggressive in your drilling and drilling more and acquiring more?

Larry just asked, it is the least of the drilling. No money included in the 750 relates to the acquisition.

Okay.

The acquisition will be a layer on top of that.

How much is that would you estimate?

The acquisition?

No, how much additional cap-ex.

The whole 750 versus 560. The 190 is all cap-ex.

Understand. Given the activity and money that's being spent there now, I money, that would -- like your 560 doesn't include spending between August on the acquired properties, right? So what I'm trying to figure out, I'm 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 -- maybe you are not thinking that way.

Hold on a minute, Joe.

Sure.

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.

Okay. That's not in the 750?

That's not in the 750. The 750 number we updated was just base Cabot. The acquisition has not happened yet. We haven't added anything in for that.

Understand. So if we are modeling the acquisition maybe a better number would be 800 or 810 or something. Is that --

Yes.

For the full year?

For the activity related to the acquisition, yes.

Got you. That's good. And then just back to an earlier issue. Like just constraints in Marcellus clearly the water permit, global water permit is going to help and you've got kind of short to mid-term disposal solutions. Are there other constraints you are worried about in the Marcellus and any other constraints you are worried about in the Bossier shale Hainesville play?

Marcellus, no, not really. I think once we have the rigs in place to do what we need to do. The frac crews are in place. In the Bossier Hainesville 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 people and rigs in the field.

And, Mike, in terms -- I asked this question about the Bossier intervals, but just qualitatively what's the difference between the Hainesville and Bossier shale in terms of what you know with the productivity and reserve recovery you can get? Can you just talk about that qualitatively?

We just don't have a lot of data yet from the Bossier shale. We have some initial test data. None of these are yet hooked up and flowing so we are not quite sure what they are going to do. They look good on the outside looking in but we will have to have some time. Of course, we have some good history in the Hainesville line up at Minden from the vertical sense and they look pretty strong and we are hoping that the horizontal legs 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 in the vertical sense looks good and we will wait and see what the horizontal well does.

Then, Mike, also, in terms of the costs you are seeing you said across the board you are seeing costs increases. What kind of level, what kind of percentage increase are you seeing versus the same time last year? Whatever kind of starting point?

We have seen increases in rig rates and certain areas we have seen increases in tubulars. We have seen 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.

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

It was a lot of issues based on operations, lease maintenance, subsurface maintenance. There was additional workover expense workover 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 3000 wells. So that was over $1 million dollars of incremental fuel costs above our budget.

Okay. Very helpful. Thanks, everybody.

Thank you. Your next question comes from the line of Star Spencer with Platt.

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

On the recycle we are on a limited basis 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's where we take our water.

Thank you.

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

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

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

Larry, we've drilled a lot of wells in this field, vertical wells. It is an almond field and as we drill down through it, we see a very thick -- appears to be overpressured shale with a lot of big shows in it. We thought that if we could put a horizontal leg in the shale we might find something interesting and so that is really the background of it. We don't have any -- we had tried a couple of vertical completions in it and we've 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.

Mike, can you anticipate a well cost?

Larry, I just don't want to guess at that. I can get back with you.

Okay. That's fine.

All right.

And then, Dan, last year we had pretty wide differential in the Rockies. You reallocated some capital away from the Rockies and into other areas. You're starting to see the wider differential back with us now and may stay with us for some time. Any thoughts on reallocation 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?

Yeah, if it does stay fairly wide in the net backs to us are not in the range we want them to be. You kind of made a list as we have of a number of different opportunities that we are looking at in east Texas and certainly trying to ramp up the Marcellus. We certainly will have enough places to reallocate capital and that's, Larry, if you look at the biggest charge that I have between now and October -- 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. We have a lot of opportunity but it is going to be a challenging to put together the best program with the best metric results. So, yes, we are looking at it to answer you succinctly and if it does blowout we will have to slow down in that area.

I looked at my notes and that Louis horizontal dry hole costs going to float around a couple million dollars and completed costs depends on how many fracs we put on it, but maybe up around $3 million. Great.

Thanks a lot.

Okay.

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

Okay, Chastity. I appreciate it, I appreciate everyone's support. We 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 that -- with some clean information if you will. And maybe a little bit more direction where our program is going to go. Again, appreciate the support. And look at this down turn in the market as an opportunity. Thank you.

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