Coterra Energy Inc (CTRA) 2009 Q2 法說會逐字稿

Good morning, my name is Christie, and I will be your conference operator today. At this time, I would like to welcome everyone to the Cabot Oil & Gas second quarter 2009 conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions).

I would now like to turn the call over to Mr. Dan Dinges, Chairman, President, and CEO. Please begin your conference.

Thank you, Christie. Good morning. Thanks for joining us for the second quarter teleconference call. I have with me today Mike Walen, Scott Schroeder, Jeff Hutton, and Chuck Smyth.

Before we start, let me say the standard boiler plate language, that there are forward-looking statements included in the press release apply to my comments today. As you all are aware, Cabot issued press releases last night regarding it's quarterly financial results. We provided an operational update, information on new officers, and announced quarterly dividend. I will touch on each of these topics this morning.

First, financially, the Company reported a solid second quarter, with $39.1 million of net income, or $0.38 per share, after removing selected items, the largest of which was related to the loss of the sale of the Canadian assets. Clearly, our hedge position aided the results, with $107 million of increased revenue coming from our counterparties for the second quarter. This brings the year-to-date hedge gain to $196 million.

More importantly, however, increased production was a contributing factor to the quarterly's financial performance. Our second quarter production matched the first quarter record production, even with the elimination of the sold Canadian production. The 10% increase over last year's second quarter came equally from success in our Marcellus initiative, and the Gulf Coast region. We expect this trend to continue, due to the results we are realizing in both areas, and the focus of our investment dollars in both the East and the East Texas.

In guidance, in regard to production guidance, we have elected to stay within our current forecast levels. We certainly are tempted to increase our guidance, with the majority of our capital being allocated toward two strong growth areas, both in the Marcellus and East Texas. However, we do have the noise of moving our Charleston, West Virginia office to Pittsburgh, and closing our Denver office, and moving the majority of our Denver employees, between our newly formed North and South regions, which may temporarily cause some inefficiencies.

Additionally, we have near term headwinds, which we all realize with high storage numbers, which may require operators to shut-in gas between now and November. With that said, our forecast could prove to be conservative. However, we have elected to leave our guidance unchanged at this time.

In terms of expense guidance, nearly all of our categories have been reduced with only one exception, which is the increase in exploration for seismic in the Marcellus. On our comment on our capital program, as mentioned in the release last night, Cabot increased it's investment program to $500 million, which remains within expected cash flow for the year. The increase came from an expanded lease effort, some additional seismic dollars, and from substituting some of our vertical wells for our horizontal wells in the Marcellus.

During the quarter, the Company used the cash proceeds from the Canadian sale to reduce it's outstanding debt. Today(Sic-see press release) our debt is at $815 million, with only $133 million outstanding on the new $500 million revolver, which we put into place during the quarter.

Now let's move to operations. I think most would agree, we had an outstanding quarter. Our Marcellus play continues to expand, and will be the driver for Cabot going forward, as drilling results continue to exceed our expectations.

We anticipate continued growth of our production and reserves at very attractive returns. To date, we have drilled 43 wells, 11 of which are horizontal, and we have nine rigs currently in the field. Two of these rigs are larger fit for purpose units, which have improved our overall drilling efficiencies.

As the year progresses, we will be trading out several of our smaller horizontal rigs we have, as we have the opportunity to add additional fit for purpose rigs. By year end, all of our horizontal drilling we hope would be done with the fit for purpose rigs. Additionally, we plan to further expand the fleet in 2010. Our team has shown a remarkable progress in reducing our drilling costs and improving efficiencies.

To give you an example, since March of this year on three consecutive horizontal wells, we have seen our drill time reduced by over 50%, and drilling costs reduced by 35%. We anticipate that with the introduction of the fit for purpose rigs, this cost will continue to move lower. We highlighted several new wells in last night's press release also. Two of the wells in the Marcellus. The Teel 8H recorded our best results to-date, and it continues to produce very well.

We are extremely pleased with the initial production rates, and the decline profile of all our horizontal wells, as they are averaging over 7 million cubic foot per day for the first 30 days of production. In fact, the Teel 8H came online June 11th, and within the next 10 days to two weeks, the 8H well will have produced over 0.5 Bcf. Pretty good returns.

With that said, we will also continue to gain in cost efficiencies, along with improvements in production rates, as we enhance our drilling and completion techniques. Additionally, our drilling has been in a fairly large geographic area, a number of miles apart, with consistent results, which provides us a great deal of confidence as we continue to expand out our drilling efforts further into our large acreage position, that we are going to see consistent results.

Looking at what is in the queue for the rest of the year in the Marcellus. We have 18 horizontals yet to spud, and we will get those wells started over the second half of the year. We also have 13 wells, seven of those being horizontal, waiting on completion and/or pipeline hookup. This work is currently under way, and we will release results as we cobble a few wells together for one release.

We also reported an excellent vertical well completion being the Teel 6. Many might wonder why we are bringing up and discussing the Teel 6 well. This well demonstrates exceptional potential in a co-mingled upper and lower Marcellus completion, using our latest thinking in stimulation technology. This completion seems to have access to the entire Marcellus interval, over 370 feet, including the Purcell limestone. We view this as a potential game changer.

I realize it is a strong comment. However, we have a controlling acreage position in Susquehanna, yet in some areas we have acreage where we are not able to properly space horizontal wells. Vertical wells may be the only way to develop some of these leases. We are confident that significant production results and returns can be obtained through vertical completions.

Another point, we are gaining momentum on and continue to improve is monetizing Marcellus production, which we think will continue to be a challenge for some, but certainly not for Cabot. Our physical take-away has increased to over 100 million per day from the Teel station. We are also expanding that capacity with the build-out of our Lathrop compressor station several miles upstream. This station, when completed late next year, will add an incremental 165 million cubic foot per day of capacity from Cabot's acreage.

These incremental volumes will ramp up during the year, as drilling success builds our production volume. Our pipeline build-out continues on schedule, and will reach our 12 to 15 miles of new pipe in the ground by year end. We are currently in the process of permitting our right-of-way for our 2010 program. All-in-all, we think we are well ahead of the game in securing the necessary capacity to move our Marcellus gas.

Now let's move to East Texas. As we stated in the first quarter call, we adjusted the program to try new ideas and evaluate the best return projects. To that end, last night we announced results from two of these ideas, the Cotton Valley Taylor sand horizontal test, and the Pettet Lime horizontal oil test. The Cotton Valley Taylor sand horizontal well shows the potential we have remaining under our Minden acreage.

We recognized early that at current gas prices, the Cotton Valley vertical program did not provide us sufficient returns to justify a large drilling program. We evaluated the feasibility of drilling horizontally in our well developed Taylor sand in the Minden area. The obvious strength of this initial well certainly gives us a level of confidence, that we can go forward with a horizontal development plan for this field.

To that end, we identified about 50 to 60 additional horizontal locations in the future. However, even with this Taylor success, we still believe there is significant upside remaining in the Haynesville lime, under the Minden field area, and we will drill our second horizontal Haynesville lime test this fall. Additionally, we are keeping a close watch and gathering the data from some of our competitors, as they develop the Haynesville shale near our acreage. Those successes suggest that the Eastern portion of our Minden acreage, certainly has the Haynesville shale potential.

Cabot's County Line project started out several years ago, when we bought the prospect as a Pettet lime prospect, and our initial wells in 2006 tested that limestone unit, but we found the overlying James Lime to have superior returns, during the time of high gas prices, which we certainly hope will return soon. The Company subsequently focused solely on the James line, and we have been successful with that horizontal program. Now with the divergence of oil and gas prices, oil makes sense, and these two recent wells which we reported on last night's release, highlight that positive impact. Both wells have held up extremely well, and confirm to the Company that a Pettet oil field underlies our James play.

We have over 70,000 acres of Pettet rights, and we believe the Pettet reservoir underlies most of this acreage. We have mapped over 200 potential locations, and will be developing these reserves going forward. The fact that most of these wells will be drilled from current James pad sites will only enhance the returns. We are currently drilling the third Pettet horizontal well, and plan to expand our activity for the remainder of this year, and into 2010, if oil prices remain where they are.

As mentioned earlier, we have also begun our first participation to exploit the Haynesville shale under our East Texas acreage. We have formed four separate AMIs, with active Haynesville players involving a small portion of our acreage position. Two of of these wells are under way. We have a 42% working interest in the first well, and we opted to keep just an overriding royalty interest in the second well. We will gather all of the data from both wells. We will not see results though, from either of these wells until early in the fourth quarter.

The other two AMI wells will not spud until later this year. We are hopeful that all will be successful, as suggested by recent releases from the area by other operators. If so, we have set ourselves up for significant growth in 2010 on 100% Cabot acreage offsetting these wells.

Speaking of 2010, we are in the process of starting our formal budget process for the year. I think we can share that we will be focusing on, to no surprise, once again, the Marcellus play and the various plays we are working on in East Texas. The take-away will be that we will be expanding our horizontal drilling in the Marcellus, plus continuing to evaluate the Haynesville shale in our County Line area, and continue the development of the Pettet and Taylor initiatives we have established so far this year.

On a final note, we are very pleased with the progress of our consolidation effort. The new management team including promotions of Phil Stalnaker, VP of our North region, and Matt Reid, VP of our South region, are on the ground in both regions, and we are already seeing tangible benefits to the change. We plan to have our new office open in Pittsburgh some time in September. We anticipate that maybe we will have some hiccups along the way, but so far the transition is going very well.

While I would like a stronger near term look for natural gas prices, I am pleased with our competitive position, and the opportunities that we have put together for our shareholders. As far as natural gas prices are concerned, natural gas I think has all the facts in it's favor, has abundant supply, a proven delivery system. It is an efficient and clean energy source, and there is an existing infrastructure available today, to displace a large portion of power generation provided by coal. I have to admit, the coal lobby has managed an effective campaign to date, at the detriment of natural gas. However, I do believe natural gas will get it's day in the, sun regarding demand at some point in the near future.

In the meantime, we will continue to conduct our business prudently, and we will reap the opportunities made available to us. With that, Christie, I will be happy to answer any questions.

(Operator Instructions). We will pause for just a moment to compile the Q&A roster. Your first question comes from the line of Michael Hall with Stifel Nicolaus.

Thanks. Congrats on the solid quarter.

Thanks, Mike.

You bet. Just trying to kind of gauge a little better in terms of expectations on 2010. Just trying to think at year end, how many fit for purpose rigs do you think you are targeting for the Marcellus at this point?

At year end --

2009, I am sorry, coming into 2010.

Okay. We would hope to have five on contract by the end of the year.

And you had talked about potentially wanting to add some in 2010. Any thoughts on how many you would be looking at?

Yes, we will add two or three more fit for purpose rigs.

So then with that fleet, what sort of well counts do you think are reasonable to think about for 2010, horizontal Marcellus wells? Is that 75 wells, 100 wells? What do you think is reasonable?

We are working on that right now, as far as getting granular on our 2010 program. We will come out with that in October.

Okay. Do you think that ballpark is anywhere, am I in the ballpark?

I will catch you this way Mike, we will have more horizontal wells in 2010 than we are drilling this year.

Okay. That's fair.

I just can't, the reason I can't get exact with it, is because we are going to have X amount of cash flow. I think it is you prudent to live within cash flow. We have other opportunities and other initiatives within the Company, and we haven't made that decision yet, on the exact amount we are going to allocate to the North, with the people we have, how efficient we can move with the people we have up there, and all of the other opportunities we have within the Company.

Okay. Fair enough. In terms of cost results to date in the Marcellus, what are the average costs looking like on your horizontals thus far?

I will let Mike pick up with that.

Yes, Mike. Right now we are at about the 3.3 to 3.5 range currently. We are working those costs down, and these new larger rigs are really showing us some improvement, and I am still hoping that we are going to be able to get our costs down to the $3 million to $3.2 million range in the near future.

That is pretty impressive. What sort of laterals are you averaging at this point?

Right now, we are between 3,000 and 4,000 feet. These larger rigs are probably going to allow us to get out as far as 5,000 feet, and we will be doing about, oh probably 10 fracs per horizontal leg on the average, maybe a little bit more in some wells, less in others.

Okay. Great. Appreciate the detail. Couple of last ones. In terms of thinking of your acreage in Susquehanna, how much of that is, maybe this has been covered in the past, but how much of that do you think is limited to vertical development?

Oh, vertical development is a small portion of our overall program, and again, we have with this Teel 6 well, have had an opportunity to tweak it a little bit more. With the perked interval and the frac, and frankly, if you look at the yields, even though we have significant yields with the horizontal wells, this vertical well yield right now is equivalent to a horizontal well.

So what was the cost on that most recent vertical?

1.4.

Okay. And so did you stimulate the limestone, or is that just flowing naturally?

Yes, we felt like with the fracs that we put in at our perked interval, we felt like we certainly did propagate into the Purcell.

Purcell. Okay. All right. And then last one, do you think it is reasonable to expect total corporate production acceleration relative to 2009 and 2010, or is it too early to comment?

We fully expect that as we gain momentum in our respective areas, that we expect continued momentum in the production increases.

Okay. All right. Thank you very much. Congrats again.

Thanks.

Your next question comes from Jack Aydin with KeyBanc.

Good morning, guys.

Hi, Jack.

This is for Mike. Mike,I guess you have several horizontal wells under production, but so far you released the IP for five. What happened to the other two?

The other two, Jack, we did have one where when we were fracing, we had a casing parting.

Okay.

And when it parted, all the frac energy went through the part, and we didn't have any stimulation down hole, and that well is going to be patched and restimulated. That will be happening as soon as we can get it put together, and then the other well is completed and producing. It just did not work out as well.

Okay. Let us go to East Texas. What was the cost of the Taylor sand well?

Just a minute, Jack. Back on the Marcellus well.

Yes.

That well is doing about 3 to 4 million a day, the one that we didn't get a real good frac on.

That is not bad. Okay. The East Texas, the Taylor sand, what was the cost of that well?

Between 6 and $6.5 million, complete.

Okay. How about the Pettet test?

They were the same as our James wells. They are running 3 to $3.2 million.

What would you estimate that you are on the Pettet?

We don't have enough light yet, Jack, to come up with a good number there. We are still plotting the data, and coming up to a number there, so we are a little bit early.

Is this the first time we have oil in that area, because I guess we thought that was a gas play, now it is turning to an oil play. It is very interesting. Could you comment a little bit on it?

Well, if you recall, a number of years ago, our initial wells were Pettet vertical and a Pettet horizontal, that we made oil out of both wells at modest rates. We didn't complete them like we are today, but during that time period we also found the James to be extremely prolific, so we always knew that the Pettet was under the James field. Now because of the economic difference in the oil versus gas, it just became much more attractive to us, so we went back in and drilled our next two wells, just to confirm the initial ideas, and it seemed to have, is working out well.

Good. Thanks. I will let somebody ask, maybe I will come back. Thanks.

Your next question comes from the line of Michael Jacobs with Tudor Pickering Holt.

Good morning, everyone and congratulations on a good quarter.

Thanks, Michael.

Wand to dive in to Marcellus and the Teel 8 well speaks for itself, and I definitely want to circle back and do a postmortem on Jack's question. Interested in the No. 6 vertical well, and kind of what you learned in stimulating the upper Marcellus, lower Marcellus, and Purcell lime, and kind of your thoughts about accessing the entire interval horizontally, what are possible completion techniques, and what are the risks?

Well, I will start, and then I will flip it over to Mike. One thing that we are trying to measure right now is in, for example, our horizontal wells, we are drilling laterally under the Purcell lime, in the lower Marcellus. We are fracing the wells. We are trying to determine the best we can right now, and have continued and will continue to run tests, to determine the effectiveness of the frac propagation up through the Purcell lime into the upper Marcellus.

And when we have a large, as we mentioned, a very large, thick gross interval, the 370 feet we mentioned, was from the top of perfs to the base of the perfs, so we are trying to determine the frac propagation. With the stimulus of this vertical well, we had some good pop pressures, and all of that. I will let Mike get into that. That we think we have effectively stimulated the entire gross interval now.

That's right, Mike. As Dan said, we opened up the entire section of the Marcellus, and we have changed up our perforation patterns, somewhat different from the past. We have also changed up somewhat our pump rates, and I think that those two elements have certainly changed the behavior of the wells, and the microseismic that we have run on earlier wells, suggest that these fracs propagate up and down through the Purcell, and we just think by opening up so many perfs above and below the Purcell, that we also access that.

I think that what this well shows you it does is that, I think it confirms that the upper Marcellus and the Purcell is probably as prospective going forward as the lower Marcellus, where the majority of, or all of our horizontal wells are completed.

That is helpful. With the five wells that are on production now, and those five wells are getting incrementally better, what are the cumulative recoveries over the first six months kind of averaging?

Well, I don't have that right in front of me. I know that we are on one of our wells, we are a matter of days away from skimming our first Bcf from one well, and when I say a matter of days, I am talking about probably 5 to 10 days. That will be the first well that we cumed a Bcf. As I have mentioned to you regarding the Teel 8, we brought that well on in June, and we have cumed in the next 10 days to 14 days, we will have 0.5 Bcf. So we have seen some very good cums.

So kind of as you are refining your completion techniques, and you talked about pump rates earlier, it seems like now you are cuming over 0.5 B over two months, when we think about a 3.5 to 4B well, that cums 0.5 B a over six months, how does that make you think about per well recoveries?

Positively.

(laughter). Okay. And then just kind of the, I guess the postmortem on Jack's questions, and then I will hop off. The well that was 3 to 4 million a day, when you go back and you look at where you placed the lateral, and then maybe can you talk about lessons learned from that well?

Yes. It was designed as a seven stage frac, and we were effective on three of the stages, and for mechanical reasons, and whatever reasons.

Okay. Great. Thank you.

Your next question comes from Ellen Hannan with Weeden & Company.

Hi, good morning. I think Jack asked probably our most critical questions, but just as a couple follow-ups, when you talk about the potential EURs on the Pettet oil wells, it may be too early, is it too early to think that the EUR would be the same as the James Lime on a BOE basis?

Ellen, this is Mike. That is exactly how we modeled them, okay?

Okay.

All right. And but we just don't know what a number might be. Give us a few months of production history, to where we see where they start to roll over, and then we will have a much better feel on what it could be. But I think the take-away, though, is that we are selling gas for $4, and we are selling oil for 60 some dollars, and the economic benefit of the oil wells is much greater than a gas well right now.

Great. Thanks. That is good. Just one other follow-up, not on that, but on the Haynesville. You talked about the four separate AMIs that have been formed, and you have got two wells drilling in one. Can you just give us a little color on are you just promoting in for drilling costs, and how much of your acreage have been devoted to the AMIs?

No, we in fact are drilling in two totally separate areas. These wells are quite a few miles apart. The one we are participating with a 42% interest, is a West offset, and includes some of our Western acreage our County Line area, and the other is a Southeast offset, which includes some of our acreage that we have contributed to the unit, but we elected at this time to make a deal on the acreage, and retain an override, and get the information from the well. So we are going to have information both West and Southeast of our County Line acreage.

And then presumably that means you have still got two other separate AMIs where you are currently not drilling, or have you not formed those yet?

Ellen, this is Mike. Yes, we have formed AMIs on the other two wells, and they will be spudding those wells later on this year, and just to make it clear, these are AMIs where we have contributed acreage. There is no promote, if you will. If there is a 1,000-acre AMI and we put in 400 acres, then we have a 40% interest in the wells. So it is just a way of spreading the risk around a little bit. And we are talking acreage here, probably less than 2,000 acres of Cabot leasehold involved in these AMIs.

Okay. Great. Thank you.

Your next question comes from Brian Singer with Goldman Sachs.

Thank you, good morning.

Good morning, Brian.

Going back to the Teel 8H, when we put this into context, the rate that you got, was there anything unique that you did, in terms of your frac technique or any unique geological characteristics, that you believe was responsible for the higher rate, or how do you think about the repeatability characteristics, if at all?

Well, yes, we did, just like every operator does, continue to try to tweak the fracs and our technique, to see if we can enhance, and we did do a couple things a little bit different on this well, and we think it is repeatable geologically, we think we are in the same section that we have, and nothing unique geologically than we have seen in the rest of the wells.

Okay. And then moving to the vertical well, also kind of putting into context when you think about the ability to tap the various, the Purcell and the various Marcellus. Does this make you want to do more of these relative to horizontals, or I guess how do you think about the future development within Susquehanna vertically versus horizontally?

We are going to be looking at the returns on both types of wells, because in our program between now and the end of the year, we have some vertical wells we have to drill, because we don't have room to put horizontals, and we have the horizontal wells that we have discussed, 18 more between now and the end of the year. We are going to look at the returns. We are going to look at how those returns affect not only the rate of return, but also our reserve replacement, our production profile, and look at all of the things that would go into determining how many horizontals we drill versus vertical wells.

But if you said that you could repeat the vertical well identically to the Teel 6, and you could repeat the 8H well, the horizontal well also identically like that, both are yielding extremely good returns, and so what makes sense on a go forward basis, that is where you run your numbers. I know that is not a direct answer, but we are going to be evaluating it. We are just very pleased, and that is why we made the comment about this could give us a lot of optionality, with this completion of this vertical well.

That is helpful, thanks. And lastly, I think you mentioned in your comments that you thought you would have 13 wells waiting on completion in the Marcellus, and some of that was due to infrastructure, and some of that was just maybe due more to the gas price environment. Can you provide a little bit more color on how much would be infrastructure constraints, versus just waiting for better gas price environment, and what gas price environment that might be?

Brian, on 13 wells that are waiting on completion or hookup, we are moving forward with those. We are not waiting on gas prices on any of those. We are going to continue moving forward. I will let Mike go into it in a slight bit more detail, but we do have a permit, or stream or creek crossing permit, which is Section 105 type permit, that requires us to get that approval before we can traverse a stream, with our lines going out into our acreage position.

We feel comfortable about all of the timings of the getting well permits, and all of the permits that are necessary. There have been some delays in getting some of these creek and stream crossings, and with that uncertainty, though we are going to get them, we will just hedge a little bit on the timing of when we are going to be able to get them completed.

Brian, we just have two wells that are waiting on this permit out of those 13, and the permit was supposed to be here this week. We will probably be waiting for it until next week to get that permit. So it is a bit of a delay, but nothing really significant.

Thank you.

Your next question comes from Biju Perincheril with Jefferies.

Hi, good morning. Couple of quick questions. It looks like you were on track to drill 30 to 35 horizontal wells this year in the Marcellus, at least to spud that many. Any idea how many of that could get completed this year?

Best guess would be 20 to 22 completed and online by the end of the year.

Okay. Is there a guess what exit rate that could leave you with out of the Marcellus?

Well, yes, we kind of co-mingled that with our guidance right now.

Okay. Okay. And then the wells that have been drilled but not completed, you would book them as proved undeveloped, or would those be booked as PDNP?

Those would be PUD bookings until we bring them online.

Okay. Got it. And then I am not sure if you talked about this already, but how many more horizontal Taylor wells are you planning this year at Minden?

We just got the results of that one. We have allocated our capital. We put in some money for that particular well, but we have allocated our capital to the Marcellus, and we are talking about these Pettet wells right now. We are going to watch that well, and we have also increased and rationed our capital, to participate in these Haynesville shale wells that we are forming with these AMIs. So we really don't have right now, we really don't have any other Taylor horizontals scheduled, just because of cash flow, staying within cash flow.

Okay. And then going back to the Marcellus well that is flowing 3 to 4 million a day, when you said you only maybe completed three or four stages, was that a mechanical issue, or something with the rock that you couldn't get the frac initiated?

Well, we are still looking at it. On several of the fracs, we could not pump away. We couldn't break it down. And we are evaluating exactly the reasons why that happened. We didn't see anything unique in drilling or anything different. We are evaluating that right now.

Okay. That is all I had. Thank you.

All right. Thank you.

Your next question comes from David Deckelbaum with UBS.

Good morning, guys.

Good morning.

Just had a couple, a little bit more granular detail, follow-up question on the Teel 8H. If you talk about just the casing that was used, and the casing pressure there?

We are using a 4.5" string with the external packers type technology, where we will drop balls and pressure up and open up the sleeves, and then we frac through the sleeves, and the pressures are up in the, up to as high at 9,500 pounds pumping pressure. So it is a pretty high pressure environment for our fracs.

Certainly. Thank you. And just to take a bird's eye view now, when you think about the lower CapEx program this year versus last year, how do you guys look at reserve bookings this year in relation to 2008, considering the greater activity with horizontal wells?

David, that is going to be a little bit early for us to make that projection. I am just not comfortable doing that.

Fair enough.

We are comfortable we are going to have a good reserve replacement. I am just not prepared to say what it is at this stage.

Well, thank you guys.

Thank you.

Your next question comes from Ken Carroll with Johnson Rice.

Just real quick on the Teel 6, in terms of that vertical well, what was the cost for that well, and if you might talk about expected EURs on that?

I don't have the EURs. A little bit early for that. But the cost of the well was 1.4 completed.

1.4 completed. Okay. Great. That was my question. Thanks, guys.

Thanks, Ken.

And we have a follow-up question from Jack Aydin.

Hi, Jack.

If you were to do a forward curve on 5/6 of those wells that you had in Marcellus, and you had a resource potential over there, based on the experience now, what would be your biases going forward on those, on the resource potential?

Are you talking about a curve fit, as far as a biased on an EUR, or something like that, or--?

EUR and the total potential in Appalachia, in resource potential for your Company?

Oh, that is TCS right now, and as we have talked about, Jack, the results so far have exceeded our expectations, and we were kind of at 4 to 6 Tcf, is kind of where we are right now. We have been very pleased with what we are seeing, and the curve fits we have, and we are seeing right now are pretty darn good.

Okay. So your biases will be higher, I assume?

Yes.

Okay. Did you guys do a tight curve on those wells, you or Mike? Could you comment on it? Or would you publish a tight curve?

We hadn't published a tight curve. We have seen a couple of tight curves out there. What we want to see, Jack, keep in mind, our sample pool is seven wells right now, and once we get a sample pool, which is a good sample pool, a large enough class, then we are going to publish that.

I think it would be misleading if we presented a sample pool right now, I mean a tight curve right now with only seven wells. I just don't think that gives the reader a good reflection of the entire acreage position. I would like to see us have 20 wells, and say okay, here is a tight curve now that fits, and that all our engineers are comfortable with.

One more question, would you consider this Susquehanna now is derisk, and on full development? If that is the case, what kind of development? 80 acres, 50 acres, 120 acres, development stage?

We are still working with that. We are still gathering information. We are still doing micro-size work out there. We are still tweaking the type of fracs to determine how far rail extents we want, and how much horizontal and vertical propagation we get, to arrive at just exactly, Jack, the points you are talking about.

And we are trying to get that information as quick as we can, so we can effectively space these wells, and we don't leave any undrilled acreage behind.

One more. I assume based on the CapEx level and the current result, your F&D costs should be below a year ago. Is that fair assumption?

I can answer finally a question. Yes.

Okay. Thanks.

Sorry, Jack.

That is all right.

All right.

And we have a follow-up question from Michael Hall with Stifel Nicolaus.

Thanks, appreciate the follow-up. Just quickly, any updates on what you are working towards on developments in Trawick regarding the Haynesville?

Well, it kind of follows back on the question of drilling additional Taylor horizontal wells in Minden. We are capacity-out on our available cash.

Yes.

And right now at Trawick, because of our rig situation, we have drilled just a couple of the shallow Travis Peak wells, and what we are doing, along with our ongoing study of the deeper section in Trawick.

Okay. Let's say you had an extra $100 million. How would you allocate that among your various, between your various opportunities right now?

Similarly to what we are doing right now.

Marcellus first?

We are seeing superior returns to every well economic and curve fit that we can see, not only Cabot's, but in industry. We like our position of where we are allocating capital, and that is up in the Marcellus right now.

And then on the Marcellus, when you talked about looking for additional firm capacity, any quantification of how much you are looking for and timing?

Well, yes, that is a good question, Mike. I will turn that over to Jeff Hutton, who is our VP of Marketing. He has been beating the pavement and just looking at that entire market downstream.

Yes, Mike. Of course, we have $100 million a day currently, or will have $100 million a day currently of back haul firm capacity. We are talking with a number of the markets, which has actually been very exciting.

The New England markets, New York and Jersey are all very excited about the Marcellus, and particularly the Marcellus play that we have that is the closest to their particular market areas. So we are working with them on downstream capacity. There are a number of different proposed pipeline projects in the Marcellus area and Pennsylvania, that may offer us different outlets for firm downstream capacity. So there are a number of moving pieces right now, but it looks like it could all come together here pretty soon.

Okay. Appreciate the color. And so are you limited by your firm, or your physical? How should I think about that?

Currently we have not had any limitations on moving gas out of Susquehanna County.

Okay. That is helpful. Appreciate it. Thank you.

Thanks, Mike.

There are no further questions at this time.

Okay. Thank you, Christie. I appreciate everybody listening to this conference call. We have a large program out in front of us, and hopefully our next call is going to be equally as successful. Again, thanks for your interest and support.

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