Coterra Energy Inc (CTRA) 2007 Q2 法說會逐字稿

Good morning. My name is Vanda, and I will be your conference operator today. At this time, I would like to welcome everyone to the Cabot Oil & Gas 2nd Quarter 2007 Conference Call. All lines have been placed on "mute," to prevent any background noise.

After the speakers' remarks, there will be a question-and-answer session. If you would like to ask a question during this time, simply press *, then the number 1 on your telephone keypad. If you would like to withdraw your question, press the # key. Thank you.

Mr. Dinges, you may begin your conference.

Thank you, Vanda. Good morning. Thank you for joining us for our 2nd quarter teleconference call. With me today I do have several members of our management team, including Mike Walen, our Chief Operating Officer; Scott Schroeder, our CFO; Jeff Huttin, our VP of Marketing; and Chuck Smyth, our VP Controller.

Before we do start the teleconference, let me say that the statement regarding forward-looking information regarding -- included in the press release apply to my comments today. As you are aware, Cabot issued two press releases last night, both illustrating our continuing success, one with the financial highlights for the quarter, and the other reporting achievements in our second quarter operations activity.

Financially, the Company again reported solid net income of $38.6 million or $0.40 per share after removing the benefit of additional asset sales activity in the quarter. This level of net income was Cabot Oil & Gas Corp's second highest second quarter results ever reported, only exceeded by last year's effort.

The quarter experienced higher realized natural gas prices, offset by lower oil price realizations, and as expected due to the third quarter asset sale last year, we had lower absolute production for the comparable quarter.

Overall, expenses were down 4.5% for the year-over-year comparable quarters. I think this is very positive, particularly in the escalating service cost environment we've had over the last several years.

Relating to pricing,Cabot experienced a 7% increase in natural gas price realizations, buoyed by $0.66 per Mcf pickup from the Company's hedge position. Additionally, we have added the hedge impact for the reported periods to the press release tables.

Oil price realizations fell 9% to $61.98 per barrel, but remained within our collared range of $60 to $80 per barrel. Cabot's overall hedge position is highlighted on our website for both 2007 and 2008, and as it relates to 2008, we remain opportunistic and will look to add to that position.

Production, as I mentioned -- absolute comparable period volumes were down as a result of our sale in last year's third quarter. However, what I remain very pleased with is our pro forma growth levels for production of 13% for the 2nd quarter comparisons, and 19% for the year-over-year period.

Because the production levels are solidly within our guidance, the posted guidance level will remain unchanged at this time. The production growth has clearly been driven by a 98% success in our 222-well year-to-date drilling program.

Moving to expenses. Overall, expenses fell in the quarter, even with increases due to compression, water disposal and treating costs and direct operations and the amortization of undeveloped leasehold in all our regions. The undeveloped leasehold are those aging areas that are no longer prospective, or have been allowed to expire due to other opportunities.

Because of this increased leasehold amortization, we are slightly increasing our guidance for DD&A in the 3rd and 4th quarters. However, guidance for all other expense categories remains the same.

Smooth operations. Last night, we gave an operational update, including an increase in our capital program. We have been asked many times about our capital plans, especially in the light of our financial position. And I believe this release will answer the majority of those questions. We are adding approximately $65 million as capital for expansion of our drilling program, and associated facilities and pipeline infrastructure. Obviously, with this additional capital being spent towards the end of the year, the impact to 2007 production will be limited, but will help augment our early numbers in 2008.

Moving to the specific areas. At County Line in our Gulf Coast region, we have made further progress on three fronts. First, we expect our pipeline upgrade to be completed by September, which will allow the Timber Star 2 horizontal James well to produce at full capacity. That well has been completed and flowing at a reduced rate of approximately 2.5 million a day.

Second, we are finalizing a trade with a major oil company there in the area that gives us exposure to an additional 8,000-plus acres in the play. This would increase our position to over 26,000 acres under lease in the prospect.

Third, we have expanded our capital program to take care of this situation, with nine more horizontal wells scheduled between now and year-end in County Line. The Company also released results for the Timber Star Number 1, a Pettet horizontal test, which you saw last night. This release indicated a test at 480 barrels of oil per day, plus a half million per day of natural gas. This well is currently shut in, pending facility design. Cabot owns, by the way, 100% in this prospect.

Moving to Mississippi, in our Floyd shale tight sand play in the Black Warrior Basin, we are currently drilling our fourth shale test, plus continuing to test an earlier tight sand well. The well we are currently drilling is our most westerly well to date. We plan to continue to evaluate this large acreage position and report our progress towards the end of the year.

Moving to the West region, our Moxa Arch area of Western Wyoming has evolved really into one of our premier development areas, due to the success of our down spacing from 160 acres to 80 acres for the frontier section. Year-to-date, we have drilled 15 wells, at 100% success, averaging reserves of 1.2 to 1.4 Bcf per well from the frontier, which is in line with our predrill expectations. Look for this area to ramp up in our effort during the third quarter.

Paradox Basin program will kick off when we spud our next well at McKenna in a couple of weeks. This 10,000-foot well will continue to evaluate gas potential in the Paradox shale group. Cabot has a large acreage position in this area.

We plan also to drill one other high-potential target in the basin later in the year. The South Gypsum Prospect, a 9,200-foot Leadville test, will spud in September. We have 6,600 gross acres on this prospect. We will drill the initial well with a anywhere from 30 to 50% working interest. This prospect has a 25 to 100 Bcf potential.

Moving to the mid-continent, also part of our West Region, we have drilled 33 wells, with a 97% success rate in the mid-continent, utilizing two rigs. With over 265,000 gross acres across the basin, we're using a portion of our capital expansion to upgrade this program. We plan to drill over 27 wells between now and year-end in the mid-continent.

Moving to the East Region, the East Region program remains on track, with approximately 10 conventional rigs running at this time. We anticipate starting up a horizontal rig in August. Our plan at this time is to drill six to eight more horizontal wells this year. To date, in our total program, both vertical and horizontal, we have drilled 154 wells. 22 wells are currently completing. 130 wells have been completed, and 89 of those have been turned inline. The pipeline crews are working diligently to hook up our gathering system to those successful wells.

At our horizontal play, we are producing five of the six horizontal wells we have hooked into the system, although at a curtailed rate, as we continue to reduce the percentage of nitrogen recovered through production. The nitrogen was used to frac all these wells.

While this is work-in-progress, we believe that on average, the reserve profile of these five wells will be somewhere between the 1 to 1.8 Bcf range -- which, when you complement it with a completed well cost of $1 million, we think this gives significant credence to the program. As I mentioned, we will be moving a rig in, in August, to restart additional horizontal drilling.

Moving to the north, our Canada region, at our Hinton area, our fourth well was recently stimulated. It tested at 12.2 million cubit foot per day, from one of the two log mountain park zones. This is the first well, as I have previously mentioned, drilled from an interpretation of our new 3D survey. We have staked additional locations utilizing our 3D and plan to drill several more wells this year in the Hinton area. We will have two rigs running in Canada for the rest of the drilling season, concentrating on our down spacing program at Musreau, our drilling at Hinton and at -Narraway, as well as Chime.

In summary, we have achieved a significant level of success with the first half of our program, and have our most active quarter out in front of us. I am very pleased with the tremendous effort of our staff and the progress of our 2007 program. We have started looking and working on our 2008 program, and we should be able to report progress in October on what we've done for our 2008 program.

For 2007, I do fully anticipate our organic reserve replacement target of 250-plus-or-minus percent to be met at year-end, with a top-tier finding cost of around $2. Additionally, I anticipate us to meet our double-digit pro forma production growth targets in our guidance. If we meet these goals, we will again be adding significant value to the shareholder at year-end.

Also, it is our strategic goal to find an efficient method to accelerate our inventory of opportunities, while still maintaining our financial strength. We will continue to work on this program.

In light of the soft environment, when you look at efficiencies, we will also have to be attuned to stock buybacks. At current levels of valuation for Cabot, at around $2.20 per Mcf in the ground, we are at the indifferent mark between pushing our staff capacity and adding capital for rigs versus repurchase of shares.

With that, I do thank you for your support and look forward to reporting periodic update on Cabot's progress.

Vanda, with that, I'll turn it back over to you, and if there are any questions, they can ask them at this time.

At this time, I would like to remind everyone, if you would like to ask a question, please press *, then the number 1 on your telephone keypad. We'll pause for just a moment to compile the q-and-a roster.

Your first question comes from Ray Deacon with BMO.

Hey, Dan. I just was wondering if you could talk about the mechanical issue with the nitrogen fracs and how you'll change the completion technique, going forward. And also maybe just some more detail on what the James Lime activity might look like, going into 2008.

Good. Ray, thanks for the question. The amount of nitrogen that we pumped in with multi-stage fracs up there on horizontal is anywhere from four to seven fracs. It's a bunch of nitrogen. And we are going into a line, as you know. We've tied into a line with laying a 10-inch and an eight-inch out into our leasehold position. And that line dumps into a line that does not have a great deal of gas in it right now.

So the pipeline specs that we are held to limit the amount of nitrogen percent that we can put into the line. And since we don't have a great deal of gas to blend with, as we would if we were hooking into a line that had a significant amount of gas into it, it's requiring us to bring these wells on slower because the percentage of nitrogen being produced from each well is greater than the pipeline specs that we can put into the line.

So our plan -- and we've looked at additional ideas. Whether or not we put in a nitrogen recovery unit out there, which is kind of a slow process or we flare these wells in greater capacity before we start putting these into the lines to get the nitrogen down. And we're looking at those options.

But right now, what we would hope would happen is, as we bring the nitrogen content down on the wells we're flowing into the line right now, and as we get more gas into the pipeline, the blending effort will help us bring on the wells that we plan on drilling out into this area into the future. It will allow the blending process to help bring the percentage down, and bring these wells on a little bit quicker.

But also, we're either going to recapture some of the nitrogen, or we might flare a little bit more of the gas on the front end, to help bring it down. It's just when we are flaring them at reduced rates -- because the flare rates are high -- there's kind of a balancing and tweaking going on, right now. And that's what we're experiencing.

In the James lime, in the County Line and all of East Texas area we're looking at, we do anticipate that to be a very active program for us. James Lime -- we've drilled a vertical well out there earlier. We've now drilled our first James horizontal well, which we've had good success with. We're going to drill an additional nine horizontal James wells out there on our acreage. And with our acreage position, we do anticipate, going into 2008, that that's going to be a significant level of activity for us, the James along with the Pettet. So we look for that to be a pretty good program for us in 2008.

Great. Thanks, Dan.

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

Hey. Good morning.

Hi, Larry.

Hi. Just in looking at County Line, I'm just looking for a little bit more information on the two wells. The first one tested 2.5 million a day. The second one had more oil than gas. What's the ratio of the first one? I know there are two different formations there. But was that expected to have more oil coming out of the James Lime, there?

Well, I'll turn it over to Mike and let him answer, also, Larry. But the James well tested at a different rate. We are flowing at about 2.5 million a day, right now. I'll let Mike visit about the gas-oil ratios.

Yes, Larry. The James is generally a dry gas reservoir. We have very little liquids involved with that. As a matter of fact, that'll be part of the story with the Pettet. The Pettet zone is higher. It's really oil zones, more than gas zones, out of the Pettet. And the goal, going forward, is to get enough James gas production to then blend with the Pettet gas, and reduce our hydrocarbon dew point that way into our pipeline system and then set up some gas lift to lift this oil out of the Pettet.

We think that there is a lot of potential in the Pettet for this oil reservoir. And probably we will see some activity on that Pettet front in '08.

(inaudible) oil and gas.

Yes.

Okay. On the pipeline front, what's going to be the takeaway capacity of that, in that pipeline?

Well, there's a lot of activity in the East Texas, in and around this area. And I'm going to turn it over to our VP of marketing, Jeff Hutton.

Okay, Larry. Initially, we expect to have about 15,000 a day capacity, hopefully here around September. We've got a second project that's in the works that may add - or essentially double that by, let's say, October. And then in addition to that, there is two or three very competitive gatherers out there in the area that are proposing some very large diameter pipes to cut through that whole area. We're talking 24-inch type pipes. So capacity should not be an issue here as we get later towards the end of the year.

What would be the timing of that second boost that would double that takeaway capacity?

Toward the end of September. Late September.

Okay. All right. Just shifting over to the Paradox. You've got, obviously, McKenna and then South Gypsum. I think there was a 3rd one, [Van Gorham]. Is that still on the agenda? Or is that being pushed out to 2008, I take it?

Yes. With the level of activity every place else, Larry, we're moving [Van Gorham] to 2008.

Okay. And maybe a question for Scott, there, just on the deferred tax rate. Came in significantly higher than what I was looking for. Do you think it's still going to be in that 15 to 25% range that you've talked about? Or is there a possibility that it comes in higher than that, going forward?

There's a possibility it comes in higher. We will adjust the guidance. It's still 15 to 25%. We need to do some research with the tax department on that. We got kind of caught with just running out of time. So we will post new guidance on deferred taxes here by the end of the week.

Okay. Good. All right. Thanks a lot.

Thanks, Larry.

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

Hey. Good morning, Dan.

Good morning, Eric.

In the James Lime play -- well, actually on both the James Lime and Pettet, do you have any estimates out in terms of EURs and well costs? Or is it just too early for that?

It's really a little bit early to give that. I think towards the October period, when we can turn these things in line a little bit and just kind of make sure they hold up as expected and all, I think that'd be a better time to be able to speculate on that.

Okay. On the James Lime well, I think you mentioned -- was the test rate like 5 million a day and just flowing at 2.5 capacity constrained? Is that correct?

Yes. It was a little better than 5 million a day.

Okay. Great. And then in the Rockies, with the Rockies prices, does that impact your drilling plans out there? And if not, at what price do you think you might consider reducing activity?

Well, the Rockies always gets hit with the differential. It does affect the percentage of capital we allocate out there. We do have a good hedge position on with our Rockies gas. We have a $7 floor with about 20 million cubic foot out there, so we feel good about that.

We do expect that differentials in the long run will relax a little bit. Once you get the new -- like the Rex line in out there, you don't have quite the gas-on-gas competition. But it has tempered a little bit via percentage of capital we allocate into the Rockies.

Okay. And then finally in Appalachia, on the horizontal program. Did I hear correctly? Are you going to dedicate one rig just to horizontal wells? And if that's the case, how many wells per quarter? What's sort of a basic outline of the drilling program for rest of year and 2008?

Yes. In, really, the rest of 2007, we're going to dedicate this rig to horizontal drilling. And in 2008, though, we'll have probably a couple of rigs dedicated to just horizontal drilling in 2008. We're going to expand our horizontal drilling program.

All right. Great. Thank you.

Again, if you would like to ask a question, please press *, then the number 1 on your telephone keypad.

Your next question comes from the line of Ellen Hannan with Bear Stearns.

Good morning. This is a question for you on Canada. Could you just refresh my memory? What is your takeaway capacity in your Canadian regions on the pipeline? (inaudible)

Are you talking about in the Hinton area, Ellen?

Yes. Yes.

We had a firm 22 million a day, firm, on that Hinton pipeline. And I'll let Jeff kind of just add to what's going on out in that area.

Okay, Ellen. We have,like Dan mentioned, 22,000 a day of firm. That's net to Cabot. The pipeline capacity was built to 50,000 a day, at the current stage that it's at. With just a little bit of compression add and a little bit of looping, that 50,000 a day goes to 100,000 a day. And with deliveries, both into two large interstate pipelines, Alliance and TransCanada. So, for short-term and long-term, the capacity should not be a problem.

And my other question -- you may have already tried to answer this, and I apologize if I've missed something. On the James Lime horizontal, do you have a cost per well for that?

Cost per well as completed well cost is approximately 3 million.

And you don't want to talk about what your expectations are for the EUR, yet?

No. It's a little bit early for that. We should be able to get to that, though, in the next quarter.

Okay. Very good. Thank you.

You bet.

Thank you. Your next question comes from the line of Pavel Molchanov with Raymond James.

Good morning. Question about your Appalachian properties. You mentioned before that both your pipeline and some of your upstream assets may be MLP capable. Can you just talk to us about your latest thoughts about that?

Well, MLP area is certainly abuzz in a number of announcements made for upstream assets to be placed, and midstream assets to be placed in MLPs. Cabot certainly has both of those.

We have a large infrastructure in the East. Our Cranberry system is about 27-2,800 miles of pipe, with significant compression on that. And we certainly have the type of assets that are low-decline, low-intensity that are conducive to MLPs.

We look at the MLP space. We evaluate what we have, as far as opportunities to place in that. There is certainly a position to take that would say if the MLPs are going to need to continue to facilitate their vehicle with additional acquisitions and assets to be placed into those, then we think Cabot, whether it is a portion of our assets placed in MLPs or whether or not we position our assets in a way that would be attractive, and secure what we think might be superior value for MLPs to dump into their vehicles, we think in both cases, Cabot's going to be well-positioned. But we continue to look at it and monitor the space.

All right. Thanks very much.

Again, if you'd like to ask a question, please press *1 on your telephone keypad.

Your next question comes from the line of Omar Jama with Owl Creek.

Good morning. I was wondering if you guys have given -- you've sold assets in the past. I was wondering if you've given any thought to perhaps shedding some of the -- either the Western assets or the Canadian assets. So far, the earlier results look pretty strong in Appalachia. And maybe rededicating some of that capital to higher-return drilling projects. Is that something you guys have thought much about?

Yes. We have. It's a fair question. We always are looking at how we allocate our capital. We look at the depth of our portfolio with the 10,000 locations we have out in front of us. And we are making efforts to create a little bit better present value on all of those locations.

Selling assets is certainly one way of doing it. I think when you do sell assets, there is an opportune time to do that. We have both -- and certainly in the Rockies and in Canada we have a significant level of activity or locations or prospectivity in our portfolio now that is unrealized.

For example, on a number of the areas that we've made discoveries, on Chime and Bolton and Narraway. Hinton, we have a significant level of additional acreage available out there that you don't recognize by PUDs. You can put it into the Probable/Possible category at this stage. But we don't think we would realize the value at this time for those types of assets.

If somebody came knocking on our door, however, and they would recognize the value as we do, then certainly we would entertain that conversation. But it is a fair question of where we allocate our capital and what we get for the capital we spend in different regions. And frankly, I think that's one of the strengths of Cabot, that we do have multiple regions to allocate. And all of them give us different input into our summation metrics that we report at the end of the year.

Canada gives us -- just like the Hinton well. We just tested that Hinton well at 12 million a day, a significant pop in our production. Where the east, for example, gives us a very, very good cost, a fine number, good rates of return and reserve replacement. But currently, the rate of return up there is not going to be equivalent to a well that you bring on at 12 million a day.

So there's a good balance, and that's certainly our objective as we put together our capital program and what we're going to be looking at as we put 2008 together.

Okay. Have you given your outlook for the CapEx breakdown looking into next year? Have you thought about reallo- -- shifting things around more?

No. We are (inaudible) in fact, we have a board meeting today and tomorrow. We have our entire management group in the office today. We have a meeting scheduled after our board meeting tomorrow to really talk and go in-depth into our 2008 program, and talk about all aspects of our portfolio.

Okay. Thank you.

Yes.

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

Hello -- Eric?

Eric, your line is open.

Yes. Hey, Dan?

Yes, Eric. I've got you now.

Okay. Sorry about that. Just a follow up on the MLP question. In terms of tax leakage, do you think that's going to be a significant issue there? Have you invested enough capital into the infrastructure and into drilling to increase the tax basis?

Well, yes. I think the tax leakage -- I think everybody that's dumping these properties into MLPs has to make that as a consideration when they put these vehicles together. And we're looking at the tax aspect of it. Certainly, our assets in the East are assets that we've had a long time, and we have a reduced book value on those assets, as far as the upstream assets.

Midstream assets, we've continued to put dollars into expanding the infrastructure, to allow us to expand our drilling program. So the tax aspect of that is something we're just looking at, at this time.

So from a tax point of view, the midstream might be more prospective, given the investments you've made over the past few years. Is that fair to say?

Well, yes, we're looking at it. But that might be a fair conclusion.

Okay. Great. Thanks again.

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

Hi, guys.

Hey, Jack.

I want to know a couple of questions. The increase in CapEx for the balance of the year, 65 million -- could you break it down, where you are going to spend that money, where you are allocating it to?

Yes. Jack, I'll just touch on a couple of points, and then turn it over to Mike.

But certainly the success we're having in County Line with the horizontal drilling is going to see probably the majority of it. We're expanding the mid-continent area, also. And also, we have added a couple of horizontal wells to the program in the East.

Second question. I thought -- I was under the impression, and maybe I'm wrong -- that you were acquiring additional acreage for the prospective [Marcella] shale. Could you comment on that a little bit? Could you shed a little more color if you're adding acreage there?

We have active programs in all of our regions right now, with the land man and brokers.

That's all you're going to say? Okay.

Now let me ask you another question. You're talking about your implied value in the [grant] of about 220, and alternatively you think, instead of doing acquisitions, buying share -- are you in the market, buying stock?

Well, we've really just recently, Jack -- the market turned soft. Everybody has looked at the weather and the storage numbers. And that convergence has created a lot of softness in the space. And everybody's given up some of their move that they've made.

When you look at now where that has brought Cabot to, we were never really equivalent to our peers in the ground. We were always under our peers on an Mcfe equivalent. But coming back to now 220 an Mcfe, it's approaching now what we look at as our replacement cost with our organic program.

And when we say that and look at that, and now, knowing that we have added to our capital program, we're pushing our staff as hard as we can. And we get to a certain level of effective capacity with the staff to be able to drill efficiently and not waste money in trying to do too much. And when we look at that, and certainly with the strength of our balance sheet, we do consider buying shares back.

We have not made any share buyback recently, though. And Scott might want to add to that.

Jack,right now, governance rules prohibit us from being in the market, simply because of the earnings and everything. Just for example, when officers are blacked out, the Company has to be blacked out, also.

Okay. The other question I have, Dan, is this. You mentioned you've got almost 10,000 locations. And you're talking about the capacity in terms of human resources and technical know-how. Now, are you giving a thought that you might want to bring somebody to join venture in some areas such as the Paradox Basin or other areas?

Yes. Jack.

To accelerate the development of your 10,000 locations?

Yes, Jack. That's a good question. I referenced in our annual report that it is a significant value that's out there. And multiple years of drilling locations are out in front of us.

To really recognize some of the value, we have to, as a management group, figure out a way to maximize the value of what we have in our portfolio. And certainly, coming up with the methodology to allow us to expand our program in a number of different ways.

We could expand it by adding to staff, which we're doing, some. We still have probably 16 to 18 open job requisitions right now that we're trying to fill. We've filled some in various different regions. So we're adding that way to expand our program. And we're ramping up as much as we can in what we think is an efficient manner.

But we're also looking at other ways of looking at maybe our locations. That would be three, four or eight years out in front of us, and maybe carve out an area that would allow somebody to come in and us still participate in some way, in some method, but also allow us to recognize significant value that's hanging out there that we're not able to get to for multiple years. But we might be able to find another way to skin the cat.

That is a consideration. It is a project that I'm trying to solve. And it will be one that we continue to work on. We're not going to try to give away anything, and we're not going to give away anything. But we are going to try to recognize value with what we have in our portfolio.

Thanks.

Thank you, Jack.

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

Hey, Dan.

Hey, Larry. How are you?

I'm doing well.

In the East -- the EUR that you'd given for recovery is 1 to 1.8 Bcf. That's a fairly wide range.

Yes.

All right. Is there anything other than rock quality that would determine whether that recovery would be in the higher end of the range or the lower end of the range?

No. And it's still a very small sample pool, Larry. We've been cautious on putting numbers out there, because we didn't want to get ahead of ourselves. And we still have a fairly large range. But we only have 5 wells that have been producing now for a month. And really, it's still early, I think, to be talking about EURs. But we felt a little bit of a need to get some numbers out there, and certainly represent and recognize that the horizontal program is a viable program for us.

I would think with additional drilling, you're going to have a myriad of different results. You're going to have better wells and you're going to have wells that are not as good. I don't know where the average is going to fall out. Obviously, we'd like for it to fall out on the upper end, and whether we can enhance that upper end by the extended drilling,getting out 34, 35, 36, 3700 feet and adding multiple fracs, or how we frac the wells as being one way. But also, if we find the fracture swarms that are maybe significantly better than the range that we found here, certainly the average is going to be on the upper end.

But rock quality and the fractures in the rock, Larry, are going to be key to our results.

Okay. And then a quick one for Scott.

Do you have the diluted share count?

One second, Larry. Six months, 98077.

Thank you very much.

Thanks, Larry.

Once again, if you would like to ask a question, press *1 on your telephone keypad. Your next question comes from the line of Biju Perincheril with Fortis Securities.

Yes. Hi. Can you expand a little bit on the cost in the second quarter, production costs, and your expectations, going forward? I see that you've maintained guidance in the second half.

Biju, we were within a penny of the unit cost. Dan alluded to the fact that we have water disposal, compression costs that impacted the second quarter, some workovers. We expect with the increased volume, that that will come back in line with those we have forecasted, so that's why we did not change the direct operations guidance.

Okay.

And then the nine more wells, horizontal wells, that you'll be drilling at County Line. Are those going to be dual [add-ons] at Pettet and James Lime?

No. Right now we are just focusing on the James Lime, with the Pettet being oily and the James being gassy. We're going to focus right now just on the James horizontals.

Okay. Thank you.

Your next question comes from the line of John Ragard, with Friess Associates.

Quick question on the Moxa area. You guys have been very successful on the frontier. And if I recall, in the past you've drilled the wells a little deeper to target another formation, the name of which is escaping me now. You had at least one successful well.

Out of those 15 you've drilled this year, is that the only successful additional pay you've completed below the frontier?

Yes, John. The Dakotas is what we have deepened the wells to, when we do. As I've mentioned, the Dakota is more of a fluvial type of channel sand that we look for. Of the 15 wells, we felt like where those 15 wells were located, based on our best-guess geology, that only five of them were --warranted deepening. And we did deepen five of those.

We've had that one success. And the other five wells, we felt like, were not economic for effective completion in the Dakota. But we'll continue with that program. Again, it's as we've always stated. It's a higher-risk program. But I can add, we think you'll find it's significant value to the program.

And the incremental cost is fairly low per well bore. Correct?

Very low.

Okay. Thank you.

Yes.

At this time, there are no further questions.

Okay, Vanda. I appreciate it. I appreciate all the good questions. And we certainly look forward to our 2007 3rd quarter to be our most active quarter, and look forward to our report in October. Thank you very much.

This concludes today's Cabot Oil & Gas second quarter 2007 conference call. You may now disconnect.