Coterra Energy Inc (CTRA) 2010 Q1 法說會逐字稿

Good morning, my name is Tiffany and I will be your conference operator today.

At this time, I would like to welcome everyone to the Cabot Oil & Gas first quarter conference call.

(Operator Instructions).

I would now like to turn the call over to Dan Dinges, Chairman, President and CEO of Cabot Oil & Gas Corporation. Please go ahead, sir.

Thank you, Tiffany, and good morning. Thank you for joining us for Cabot's first quarter teleconference call.

With me today are several members of our Management team, including Mike Walen, Scott Schroeder, Jeff Hutton, and Matt Reid, our VP Regional Manager, and others.

This will be Mike's last public appearance for Cabot as he retires tomorrow, and again I want to thank Mike for his many years of dedicated service and contribution. Mike, we're certainly going to miss you.

Before we start, let me say the standard [border plate] language and forward-looking statements included in the press release apply to my comments today. We have many things to cover and expand on from the two press releases that we issued last night. We will briefly cover the financial results, the recent operation milestones and our progress in the matter with the Pennsylvania DEP. I will be brief so as to allow ample time for Q&A following my comments.

For the financial results, Cabot Oil & Gas reported financial results last night that exceeded consensus expectations, have or lowered natural gas prices even with higher production, could not offset the previous year. As the softness in gas -- in the natural gas market continues, from a clean earnings perspective, net income was $30 million. Select items for 2010 include primarily stock compensation and mark-to-market basis hedges. As stated, lower natural gas price realizations were the main factor in the lower net income.

For the balance sheet, our debt level increased $110 million from year-end to $915 million as we establish a sizable footprint in the Eagle Ford Shale and continued blocking our Marcellus position, both of which are certainly key areas going forward.

In terms of production, as we mentioned on the year-end call, we would be towards the low end of our guidance for the first quarter due to the delays in permitting, stream crossings earlier in the year and the capacity constraints in the second half of the quarter for our Marcellus production. You may recall we reached maximum capacity at the Peale station up in Susquehanna around the middle of February and commenced free-flowing Marcellus gas at our Lathrop station in early April. Production for the total Company year-end ended at 295 million cubic foot equivalent per day, and now at quarter-end, we are at 325 million cubic foot equivalent per day, and growing.

On the operations, I may expand on the operations release. We have numerous wells that strengthen our position in core areas in the Marcellus, in the Haynesville, and the Pettit. So we also have our best well in the Taylor Cotton Valley Sand confirming a good rate-of-return project in Minden, and we also have success on our initial oil drilling in the Eagle Ford, another good rate-of-return project for our portfolio.

Now let me move into some of the details. In the Eagle Ford in south Texas, the Company has completed its first horizontal Eagle Ford well. This well, a 100% working interest well, had a lateral length of nearly 3,000 feet and was stimulated with 14 stages. The well tested at a rate of 334 barrels of oil a day, and 142 mcf per day. Cabot holds approximately 61,000 gross, 52,000 net acres in the oil win of the play, with probably 300 to 350 potential locations, and a resource potential of 60 million to 140 million BOE. A second Company-operated well is scheduled to spud in early to mid-summer with three additional wells being drilled in 2010. This is exciting as we continue to build our position. We have had initial success and the concept was significantly reinforced by recent peer presentation, along trend with our acreage.

Let's move to east Texas. We continue to focus on two main areas there, the Haynesville, and Bossier Shale play and our Pettit oil program.

In the Haynesville, as previously announced, Cabot has successfully drilled and completed its first Haynesville well. The King No. 1, which we had 69% working interest, was drilled to a depth of 18,364 feet and a lateral of 4487. After 14-stage stimulation, the well tested, as we previously reported, at 19 million per day, and the new data point for us is its 30-day average of 15.2 million cubic foot per day.

Drilling operations are underway on our second operated well, the Walters No 1. We have 54% in this well, and Cabot is also participating in three outside operated wells that are currently drilling with working interest between 20% and 41%. Cabot has participated in the drilling of additional outside operated wells that has been -- additional operated well that has been drilled and cased. We have 29% of this well and we're waiting on completion. With Cabot just starting its Haynesville drilling, we anticipate getting into the stimulation queue sometime in June or July for our well.

We're encouraged by the Haynesville wells with the high initial rates and certainly excellent recoverable reserves. And we're particularly excited about the middle Bossier potential on our acreage in Shelby and St. Augustine County.

Moving to the Pettit, in our Pettit oil play in this area, the Worsham Oil No. 1 and the Worsham Unit B No. 1 were stimulated with ten and 14 stages in the lateral lengths of 5500 feet, and 5471 feet, respectively. The Worsham Unit A No. 1 is currently flowing back to the Worsham Unit B No. 1 produced at an initial rate of 1209-barrels of oil per day. With these results, Cabot has increased the number of Pettit wells to be drilled in 2010 to 13. In 2010, four wells had been drilled and completed. One well is waiting on completions, and eight wells remain to be drilled. Average initial production from the wells drilled in the field is 485 barrels of oil per day, and 2 million cubic foot per day. With prices 20 times higher for oil than natural gas, we look to drill more Pettit, which has the added value of holding our undeveloped acreage to all depths.

Our James, brief comment, at County Line, we had five James wells that were drilled and cased but not completed in 2009. Those have now been completed. The wells had an average initial production rate of 6.1 million cubic foot per day.

And moving up to Minden, our third Cotton Valley Taylor horizontal well has been successfully drilled and completed. The Birdwell 11H, 100% Cabot well ,was completed in mid-April and initially tested at a rate of 11.1 million cubic foot per day. This is a higher rate than the first two horizontal Cotton Valley Taylor Sand wells that we drilled. They had initial rates of 9.5 million and 8.9 million cubic foot equivalent per day. These wells continue to provide superior economic returns with EURs of 6 bcfe to 7 bcfe, and a very low finding cost. In addition, this acreage is HBP, so we will be very selective as to our timing and pick a more on opportune time to drill more Taylor wells, although returns are very compelling.

Now, let's move to the north, the Marcellus, actually continues to be our crown jewel for Cabot, and certainly is developing into a true Company maker with exceptional economics. Since we started, we have paid millions of dollars in lease bonus and royalty. And we have also hired 64 new employees, with many additional positions yet to be filled.

We continue to lease acreage in our core area, and have increased our position to nearly 200,000 net and gross acres. More importantly, our Marcellus program continues to yield exceptional well results, and production is ramping up quickly. We are currently producing at a maximum infrastructure capacity of approximately 115 million cubic foot per day from the field. Phase one of our Lathrop station is complete, which allows us to free flow gas into the Tennessee line, as the press release highlighted. Phase II, which is the compressor start-up phase, is well under way, with the compressors and the dehy equipment set on the site, and start-up schedule for late May.

I know some of you have expected higher production rates for the quarter, but we are close to ramping up our production. At this time we have 18 wells in various stages of completion and a number of wells with 50 frac stages will be ready to turn in line immediately at the compressor start-up. Cabot plans to drill 81 wells total in 2010 although we may adjust this schedule by a couple of wells, depending on our capture rate of new leasing.

Year-to-date in Susquehanna, we have drilled 11 horizontal wells for a total of 12 wells for the quarter. Cabot recently added a sixth fit-for-purpose rig in April and has a seventh rig scheduled to arrive in May to fulfill our program. At the end of 2009, Cabot set forth a series of 2010 initiatives to continue to improve our results and efficiencies in the Marcellus. Three of those initiatives were completed in the first quarter. Our recently-drilled and cased -- we recently drilled and cased our longest lateral well to date at 5,000 feet. We drilled our first well in 17 days from spud to rig release and that well had a 4300-foot lateral.

And lastly, we completed a 15-stage frac that went into the line at 14.6 million cubic foot per day, and 13 -- excuse me, 1730 pounds flow casing pressure. This well was curtailed due to current sales point capacity limits, as we've discussed, and it has been flowing less than 30 days, so it was not included in the population highlighted in the press release.

With the robust production rates that we're seeing, we have taken additional steps to ensure that we have adequate physical takeaway capacity, with the execution of three firm transportation agreements. You will recall that we announced at our last operational update, in partnership with Williams to build a 20-inch pipeline to the south that guarantees us a minimum of 150 million cubic foot a day of firm capacity from our Susquehanna compressor stations, to Transco.

Last month we executed a binding agreement with a private midstream company that also provides for a minimum of 50 million cubic foot per day of firm capacity, with expansion opportunities. This time, we're going to go to the north. This project will enable us to move a rig to the northern tier of our acreage position and establish production up there. The pipeline project is slated for completion in early 2011.

Also, we executed two binding agreements that will allow an additional 50 million cubic foot a day to flow directly to Millennium Pipeline in New York via the Tennessee Gas Pipeline. Completion of this expansion is expected approximately November 2011.

Regarding the Pennsylvania DEP matter, Cabot takes safety in all environmental matters extremely seriously. As Cabot announced Tuesday night in a press release, we will continue to cooperate fully with the Pennsylvania DEP to remedy and resolve the items from the consent order. I am not going to rehash the order or the first or second responses from us publicly, but I am happy to answer questions on this issue during the Q&A session.

Finally, on our guidance last night, we posted updates to our guidance for 2010 that held full-year production equivalent guidance in the previously-disclosed range at a growth rate of 18% to 22%. Our initial liquids guidance from October of 2009 expected a little bit more Pettit volumes at this stage than has occurred, but this is offset by our better-than-expected natural gas production.

We exited the quarter at 325 million cubic foot equivalent per day, and in terms of expenses and capital, those were left unchanged. I would note, however, that with our leasing success, the potential $65 million wedge should be added. Additionally, we continue to look for good leasing opportunities in our core areas. I'm very excited about our program that we have out in front on us in (inaudible - technical difficulties) regions. As you can see we are flush with opportunities, good rate of return opportunities for years to come. Additionally, we have several other interesting projects that are in its early stages of evaluation.

Tiffany, with that, I'll be more than happy to answer any questions the group has.

(Operator Instructions).

Your first question comes from the line of Brian Lively with Tudor, Pickering, Holt.

Good morning.

Good morning, Brian.

Your natural gas production guidance for the second quarter is up about 40 million to 45 million a day sequentially. How much of that production growth is related to the Haynesville versus the Marcellus?

Well, we didn't have any Haynesville production in that early guidance. And now, we're rolling -- or we had very little. Now we're rolling in a little bit of the Haynesville.

But second quarter, we are going to be somewhat limited on the Haynesville production, just trying to get the frac crews, the pumping crews in there. Now when you're not an operator that has lined out multiple wells out in front of us, it is hard to stage in there, so what we're doing is having to pick windows of opportunity to be able to bring those frac crews in.

Okay. So the production growth then, as I take it, is largely related to the Marcellus? And is that related to the increase in the infrastructure with the second phase?

Yes, yes.

The free-flowing gas that we're able to put through there most recently, and that is just basically us putting the wells directly into the Tennessee Pipeline, and bucking the 1,000-pound pressure in that pipeline, and then the additional is going to be once we start cranking up the compressors which should be later next month.

Okay.

On the oil side, with lower oil production guidance, could you give us some more color, and I think you mentioned briefly that the Pettit may be declining a little more than you expected, could you provide some more color on why the oil production guidance is down a bit?

I think, Brian, that we thought that we would have Pettit wells drilled and completed a little bit earlier in the quarter than what we actually did. And some of the earlier Pettit wells are falling off a little bit quicker. They are still very, very attractive but just not as high initial rates that we had experienced earlier.

Okay.

And switching over to the Eagle Ford, some operators had talked about completing wells in the upper Eagle Ford and possibly fracking into the Chalk. Others talked about competing in the lower Eagle Ford. Could you give some more color on what your completion practice is today and kind of expectations going forward?

Well, right now, we have drilled and completed in the lower Eagle Ford, and don't have any short-term plans to frac into the Chalk. Although obviously it depends on how much fracture growth you do get that you might access the Chalk anyway.

Okay.

My last question is on the rate that you put on the first Eagle Ford well, the 334 barrels a day, I think you said today that that was the IP rate. If that is correct, then what is the current rate, how is the well performing?

It is performing very well. It is still producing around 225 barrels to 250 barrels a day.

Okay. Thank you.

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

Thanks, good morning. A couple of questions on the Eagle Ford. Can you just talk about the potential outcomes and strategy, assuming the next couple of wells do work, where are you kind of from an infrastructure perspective and how significant do you think this could be looking ahead to 2011? That is maybe the first part, and the second part is, if you do accelerate activity in the Eagle Ford beyond these next few wells, you would think of that as additive to your CapEx or would you pull some activity down somewhere else in the portfolio?

First off, we have leases down there that we have taken say within this last year, and our primary term expiration and undeveloped lease is a consideration on how we're allocating capital, just like majority of the other companies in our peer group out there. We will continue to capture acreage in the Haynesville/Bossier area, as we are doing. Again we have term on our Eagle Ford acreage down there.

The wells that we have scheduled for 2010 are included in our capital program that we have laid out. If we do ramp up the program beyond what we've discussed, it would be additive to our program, and certainly juggling the balance sheet with operational opportunities and leasehold success is something we do on a daily basis, and we would look at how we would get arms around all of the opportunities we have.

But again, back to your question, the wells that we have forecast in the Eagle Ford for 2010 are included in our program.

And so I guess when we think about it from a natural gas drilling perspective, outside of the Marcellus, are you essentially drilling the minimum level of the whole acreage across the portfolio? I.e., if gas prices stay at these levels into 2011, given that you have less there -- or are likely to have fewer hedging gains you would kind of maintain the current level of activity because there is not a lot of room to reduce from here with that acreage expiration?

Yes, we have -- that's correct.

We have laid out a program out in front of us that allows us to capture our acreage, but we, in our gas areas, we are not over drilling in the gas areas, just to be drilling. We are capturing primary term acreage.

A good example of that is the Minden Cotton Valley well we drilled, horizontal well, that particular well has excellent economics, and the returns are every bit as good as what we have seen in the Haynesville, but we have elected not to drill any additional wells up there because that acreage is HBP.

Great. Thanks. And one last one is, was there anything unique to your particular Eagle Ford location or portion within your acreage that you think would make it either more significant or less significant versus other wells you expect to drill?

No, it's just going to be an area that we had focused on early on. We had bought some leases in this area, were some of our early acquired leases, and we started moving forward and getting permits and getting lined up in locations set and all in one of our early area leasing area, and that's where we drilled our first well. But other than that, nothing unique to where we pick the location.

Thank you.

Your next question is from the line of Jack Aydin with KeyBank.

Hey, guys.

Hello, Jack.

Mike, good luck to you, again.

Thank you.

Dan, regarding the Eagle Ford, what kind of a decline you see? And I know it is the first well. What kind of decline you are seeing?

Second, I know you throw numbers, about 60 million to 140 million, and also you give a little bit the number of wells. So you talking about in a way spacing somewhere in excess of 140 acres per well? Could you elaborate little bit more on that?

Okay. Well, I think I could -- I think it might be summed up, because it was a fairly well-attended presentation by one of our peers, and they laid out a very detailed descriptive analysis of the Eagle Ford that kind of had acreage spacing, they had EURs, they had anticipated flow rates, and our acreage is exactly on trend with that peer that laid all of those out. So, versus kind of going over the -- re-doing the presentation that is out there that had considerable detail, we agree with that presentation.

I have it in front of me.

Good.

Okay. All right. Thanks a lot. That's it for me.

Your next question is from the line of Ellen Hannan with Weeden & Co.

Good morning.

Good morning.

Just a couple of follow-up questions again on the Eagle Ford.

In terms of the acreage position that you've put together, can you talk about -- again I may be covering ground again, but how many wells do you think you will need to [HVP] your acreage in terms of how you were able to kind of block it up? And secondly, have you run into a situation there where you have had to lease the water rights separately from the mineral rights?

We have not had any circumstances to lease water rights separate from mineral rights, and we are developing our program with discussions with some of our offset leaseholders in making a determination of units configurations and what we would be doing as far as the development of our primary term acreage, and once we get all of that together, which is a dynamic discussions right now, we will be discussing that in further conference calls.

Okay. One separate question on the results that you talked about in the Pettit, does this cause you to change your EUR assumptions on those wells?

Not really, Ellen. We have -- these newer wells, we've kind of moved to the eastern side of our acreage block, and we're getting some excellent results coming forward now, and I think that we will stand pat with our reserve estimate there.

Thank you very much.

Your next question is from the line of Michael Hall with Wells Fargo.

Thanks. Good morning.

Good morning, Mike.

Just wondering, can you talk a little bit more about your cost of entry in the Eagle Ford, what you kind of paid on an average per acre basis at this point and what you're paying today, as you continue to lease in the area?

Well, our acreage position right now is less than $1,000 per acre. And we continue to look for opportunities out there. And it is our policy where we're active in leasing, we do not discuss bonus consideration.

Okay. Fair enough.

And can you talk a little more about midstream availability that you're seeing or hearing maybe in the oil window, there is a little more investment needed on the midstream front, would you agree with that? And can you discuss your outlook there?

Are you talking about in the Eagle Ford?

Yes, sorry.

Well, there's couple of things, then I will turn it over to Jeff, our VP of Marketing. I know we've had, I've had a meeting with, for example, Energy Transfer. They have a number of projects that are going on down there, and expansion projects that they have. They recognize the amount of resource potential in the Eagle Ford, and they are moving as we speak to develop a number of areas and expand projects down there.

Oh, I would concur with Dan, and might add that to date, we've not had any hauling issues. Obviously, there is a lot of activity, but I think the industry is gearing up to make sure everything moves.

So would you plan to kind of truck volumes up until, call it maybe 5,000-barrels a day, give or take, that sort of level is what I've heard is the economics are kind of break-even on trucking versus piping? Is that an accurate assessment?

Yes, and right now, keep in mind we have our focus primarily with capital allocation going to Marcellus, and also primary term maintenance in the -- I mean primary term capture in the Haynesville/Bossier, our first well in the Eagle Ford was successful.

I think we will gain efficiencies of our completions techniques in the subsequent wells, but we have not put together a large expansive program in the Eagle Ford at this time, with the number of wells that we're talking about.

So our -- so initially, Michael, our -- we are going to be trucking our oil out initially, and contemporaneously working on the expansion of our program, and other opportunities for our transportation.

Okay. Great. Thanks for the color.

One more on the Eagle Ford, on completion availability, any outlook there? I know you've got a pretty limited program at this point, but just curious what you're seeing.

Let me turn it over to Matt Reid.

We're somewhat limited there. Not quite as much as we are in the Haynesville. We can't get frac dates on just a phone call, but we're not basically tied into being restricted by a limited number of companies that can frac down there. And so our frac dates are fairly reasonable in the Eagle Ford.

Okay. And then in the guidance, on the production mix, if you will, the somewhat lower oil guidance, is there any Eagle Ford assumed in that production? I know you said it is in the CapEx.

Yes, but a small amount.

Okay. Would it be fair to say then, if you have continued success in the Eagle Ford, there may be some upside within that oil guidance or -- am I getting ahead of myself.

Let's not overjet because remember there's only four wells for the total-year program at this point in time, too.

Fair enough.

And then last one, quickly, on acreage additions you had in the release, upwards of, I think, $70 million, $68 million, maybe, in potential acreage CapEx, is that primarily just Eagle Ford and Marcellus? How much of that kind of split between the two? And then what are your most recent acreage costs up in the Marcellus?

We have picked up acreage in both areas, and continue to acquire acreage in both areas. And I don't have the exact split between those two areas. And we are still active in our area of Susquehanna and where we do have active leasing programs, we're not going to discuss what we're paying our potential lessors.

Okay.

And then one more, if I may, in the Marcellus. Have you looked at or are you considering intentionally choking back the wells to help with compression needs down the road? What are your thoughts on that?

Well, we have a number of wells that we have restricted in the Marcellus. We have wells that, as we mentioned, we have over 50 stages that are backlogged right now. We have a number of wells that we have in the queue that we are in the process of completing and adding more stages to complete. Again, a number of our wells are restricted at this stage. And frankly, if you would have looked at this eight months ago, ten months ago, we thought we were building out our infrastructure in a timely manner.

We moved up the construction of the Lathrop station, because we saw early success, and as we've continued to expand and we continued to improve our initiatives up there, our longer lateral, more fracs and quicker drill rates and efficiencies, we have just overtaken the timeframe of our infrastructure start-up date, and -- which is a high-class problem.

And again, we anticipate us putting a significant volume of gas into the Lathrop station once we can crank up the three compressors on site.

And initially, I might add, the initial phase, which is -- what we're calling a second phase, is the start-up of the compressors, we have three compressors that will be starting up early on. That will be about 65 million cubic foot of additional capacity. And then towards the -- in the summer, middle of summer, we will have three additional compressors that we plan on cranking up there also, which would get us up to total for the facility, 165 million cubic foot per day. And obviously, it is going to be our intent to fill that capacity as quickly as we can.

Good deal. Appreciate the color. And agree it's a classy problem to have.

Yes, love it. Thank you, Michael.

The next question is from Gil Yang with Banc of America.

Good morning.

Regarding the Haynesville frac backlog, are you seeing any changes in that? Or is it still sort of as bad as it ever was, or is it getting worse?

Are you talking about on getting the pumping equipment to the location?

Right.

Well, we're seeing, since Dan mentioned, we don't have a major program up there, like many of the other operators do. We have to get in the queue and take dates when we can get them.

We try and schedule our fracs two and three months in advance. And in a vague time period between two and three weeks. Right now, we're scheduled about two months out from the end of the drilling and completion right now.

Okay. You don't have enough activity to be really be able to tell if it is changing at this point?

Right.

We do not, that's correct.

I would anticipate, however, with the announcements that we've heard, some of the reallocation of capital that certainly it stands to reason that it might become a little bit better, but we have not seen that.

Right, okay. In the Marcellus, do you have enough wells drilled and not completed behind pipe frac stages to meet your guidance for the year? Or do you still need to drill and complete and put on additional wells.

Well, our guidance has taken into consideration our full-year program, as we have laid our guidance out there, we have a high expectation that we're going to have no problem being within our guidance or we have good success, we might even be above it.

Okay.

In the Eagle Ford, when you say you're on trend with other operators, are you sort of inter-laced with the other operators, or are you east/west, north/south of the other operators -- but along the same trend lines?

We're inter-laced with the other operators.

Okay.

Could you -- in the well that you reported, based on what the other operators seem to be reporting, could you talk about what the other operators are generally seeing, and what the differences are between what you're seeing and what you need to get to to get to the same results they have?

Well, Gil, I'm not going to rehash the peer report. It was like a 200-page report and very detailed and available out there.

But I will say that this is our first effort. We have seen other first efforts out there. And I think early time data that we see in our well is very consistent and an overlay of the early timed data that we've seen in peer wells out in the area. And again, that we have seen nothing to deter us from believing that the EUR expectation, or return expectation, of our acreage in the Eagle Ford is going to be any different than what has been discussed out there by others.

Okay. All right. Thank you very much.

Thank you.

Your next question is from the line of Marshall Carver with Capital One Southcoast.

Yes, good morning. A couple of questions. On the eight horizontals that you put online in the Marcellus for the 30-day rates, do you have the average lateral length and number of stages for those?

Marshall, those would be in the range between about 2800-foot to 3800-foot, something in that order. Not many of those are the long reach laterals yet.

Okay. Thank you.

And on the Eagle Ford well, the press release talks about it being 334-barrels a day, and strengthening. The 225- to 250-barrel-a-day rate that you all mentioned for the well, was that an IP rate or is that where it is now? I'm just trying to resolve the time that the well has been online and --.

The 334 rate was the IP rate.

Okay.

And at the time of the press release, or before the press release, that well was stabilized and was cleaning up and getting somewhat better, but it has turned over and started to decline slowly, which is not unexpected.

Right. And how long has the well been online?

It is online roughly 30 days, maybe a little longer.

Okay. Thank you.

And then one last question, the number of Cotton Valley horizontals, how many -- what's your inventory locations in that area on a net basis?

Our locations in the Taylor horizontal are roughly 30 to 50 central locations.

Okay. Thank you.

And congratulations to Mike on the retirement tomorrow.

Thank you, Marshall.

Your next question is from the line of Ronny Eisemann with JPMorgan.

Hi, Thanks, guys. My question was already answered.

Okay. Thanks.

Your next question is from the line of Biju Perincheril with Jefferies and Company.

Good morning. You talked about stream permits delays earlier in the year. Do you have those permits now? And for this year's program? Or do you anticipate needing more such permits?

We do have the permits in hand now, and we're continuing to lay pipe out there, and we will continue to secure additional permitting. But we just had a period in there where we had a delay.

Yes, Biju, really that permit was kind of a one-off deal.

We generally bore all of the streams so we don't have to get permits across it. In this one case, the boring didn't work. And we had to go back and get an actual physical stream crossing. And that's why it took so long, and it delayed the laying of that one piece of pipe.

But our standard operating procedure is to bore the wetland and keep away from the permit process.

Okay. So for the remainder of this year's program, if the boring works, if you have the same issues, do you -- could this be -- would --- do you anticipate it needing more stream crossing permits?

We don't anticipate having to have more stream crossing permits.

Like I said, that isn't something that we go forward looking to do. It is only if we are -- have some issue on physically boring the rock, as we get in this one case.

Okay. Got it.

And the other thing is that we're getting more wells spread out, and not all dependent upon just a pipeline, in this particular case that Mike talked about. We had a couple of fresh wells that we had drilled, completed, we had in our early forecast. And with our forecast number being a smaller number, it did affect our expectations.

Now, we're getting a pretty good diverse spread of wells that are coming in from different areas, and not all dependent upon a pipeline, or a boring that would -- that I hope would not significantly delay any production expectations.

Okay. Perfect.

And then the Eagle Ford well, did you ever disclose what the cost on this first well was?

The average cost, this well, we took deeper and explored some deeper potential. But the average cost is going to vary somewhere between the high $4 millions to $5.5 million.

Okay.

And then if I look across your acreage, it just looks like on the western side of what you have leased up so far, is that fair?

Biju, I'm not really following the question.

Is this on sort of on the west edges of your Eagle Ford acreage position, this particular well?

Oh, this particular well? No, it is kind of --.

Middle.

-- kind of in the middle.

Okay. And one last question.

Between the Eagle Ford and some of your activities in Montana, it looks like there is some effort to add more liquids to your production mix. At this point, with the success you were having, any sort of targets or timeline that you would put to get more oil?

Well, we still are looking at a five-year Company -wide program I've discussed earlier the five-year, actually ten-year program we're developing in the Marcellus area. We are also putting together a Company-wide five-year program that, again, is going to be a pretty dynamic document.

But it is our intent in balancing with capturing our primary term acreage to add in this commodity price environment more oil, more liquids, to our production profile.

There is one thing that would be of note, if you look at it from a percentage perspective, though, that the ramp-up that we're going to see in the Marcellus is going to be I think fairly dramatic, and so percentage-wise, we might not see a large change, but in actual number of barrels per day we produce of liquids, we think that is going to go up from this point forward.

Okay, and how much acreage do you have in the Heath?

What's the status? I don't think we put that out there yet.

Okay, that's great. Thanks. That's all I had.

Okay. Thanks, Biju.

Your next question is from the line of Ray Deacon with Pritchard Capital.

Yes, hi, good morning.

Dan, I was wondering, are these, the Eagle Ford well, was it about 5500-foot depth? And is 100 feet to 120 feet of pay sound kind of reasonable for this area?

I don't think we gave the depth.

Okay. I got well costs you gave, anyways.

Yes.

And I was just wondering, even with not a lot of growth in the Marcellus, it seemed like costs were a lot lower than I thought, cash costs, I guess what was -- what drove that?

Well, I know we're getting efficient on our drilling up there.

For example, our last well we drilled was from spud to rig release was 17 days, and we just made a trip up there yesterday, our entire Board, we had our Board meeting in Pittsburgh at our new office up there, our entire Board wanted to visit our Susquehanna operation and evaluate our progress up there. Under the Safety and Environmental Committee of our Board, we carried our -- and other members of the Board that are not part of the Safety, Environmental Committee, decided to go up there with us. And we had a good show-and-tell of all of the areas, discussed the Pennsylvania DEP operation, went by some of the wells that the DEP has asked us to get involved in and plug. But back to your question, we have our efficiency of our program, that is maybe reflective, and also the timing of some of our operation.

Got it.

So I guess just one more quick follow-up. But it seems like, well, the DEP must be pleased with what you're doing, because it didn't seem like it slowed down your ability to get permits at all. So I guess -- does it look like it is not going to affect permitting going forward, I guess is the question?

Well, one thing you have to keep in mind that is just factual that we have an area that we were up there initially that we started drilling in and we did not sample the water wells for methane. Subsequent to this event, as we discussed in our press release, we have began to take pre-drill samples of not only the entire contents and evaluation of the water, but also now determining the percentage and amount of methane in the water wells up there.

And with that information, and certainly with our cooperative working with the DEP, all the wells that we are drilling outside of this area that has caused the initial concern, all the areas outside of this area, we are having no problems with methane in the water wells, although the water wells had pre-drill methane in them, we're not have any problems with the DEP, on them advising us that we have contaminated any wells. And our operations have been certainly evaluated and scrutinized by the DEP.

We've been in compliance with the DEP orders, and we have, I think, enhanced some of the location building operations out there, and to assist the DEP in mitigating any concerns of surface exposures, environmental risk and the cementing and casing operations that we implement in our wells right now are in full compliance of DEP regulations, and we don't have any problems outside of this area that's been identified. So we continue to drill outside that area, and we would expect those operations to continue in compliance with DEP regulations, and expectations from this point forward.

Got it. Great. Thank you.

And just could I ask also one -- is the Eagle Ford well, is that on pump after a month, or not?

Yes, we have -- took early time free-flow rates and then implemented pumping operations.

Okay. Great. Thank you very much.

Your next question is from the line of [Brian Kuzma] with Weiss Multi-Strategy.

Good morning, guys.

Good morning, Brian.

Could you tell me what your Marcellus production average for the quarter?

I know we're ramping up and we've been kind of up and down as we have been working with some of that free-flow gas in the Lathrop station. But probably --.

95 to 100 --.

-- say 95 to 100 million a day would be -- Scott is telling me would be a good number.

I got it. And that's the net number or the gross number?

Gross.

It would be the gross number.

Got it, okay. And I also wanted to ask, these wells that are 8 million a day, on the 30-day rate, that is clearly ahead of your type curve, I mean what happens as you guys --- you guys keep drilling these wells, what happens throughout the rest of the year? Because it seems to me you'll have to drill a lot fewer wells, to -- if you kind of knocked out the infrastructure.

Again, we are very pleased, Brian, obviously, with the results that we're getting, and we're excited about our new initiatives, and what we've been able to do there.

We have started earlier-than-anticipated in our next compressor station. We have started that operation. And we are also looking now out towards our fourth compressor site, and doing some early-time work on that particular site.

So -- and as Jeff has been a VP of Marketing, has been doing, he is trying to get out in front, also, on the firm transportation side, as we've announced, signing up some additional firms. So we are making every effort to stay out in front of our production.

Again, this Lathrop station is a fairly significant station. We were up there by that station yesterday, with our Board, and it is coming along very, very well. Three compressors on-site, dehy on-site, hooking that all up right now. We have already poured three additional slabs for the three additional compressors and we are also now doing some engineering design work. We have enough room on this site for another large compressor, beside this train of six, that would -- and could possibly get that particular compressor site location up over 200 million cubic foot per day.

So we're doing things, scrambling, and using all the technical resource and certainly pushing our guys and they're doing a great job getting this thing strung-up. Mike is making a great point here, Brian, also.

Yes, Brian, another issue that of course we're out there building a lot of compression, but this is that dry gas, pipeline-quality gas, so we aren't having to strip liquids, and that is a big, big positive for getting these wells online timely.

But then the strategy going forward then is not to cut back drilling, it is to build additional infrastructure to handle the higher-rate wells?

Well, we have a multi-tier options that we're looking at on our multi-year program, and that is how, one, we capture our primary term acreage, and we have extensions available under some of our leases on our primary term acreage, and we're running dual tracks, keeping -- trying to keep ahead of our existing production capabilities, as these wells come in better than anticipated. And we are also trying to capture the primary term acreage, and looking at it two ways. One, if we keep drilling, without extensions, how much acreage we capture; and then making the decision that if we do extend some of that primary term acreage into another five-year term or so, does that give us the flexibility to slow down some of our drilling.

We're trying to look at all of that, as we go forward.

I got it. And so on the compression side, you will have 110 at Teal, 165 at Lathrop after this summer, and then these other projects that you're talking about, like roughly when would they come online and, again, what size would those be?

We would probably look at a similar size facilities, and the first one would probably be mid-2011.

Okay, got that.

And then just as a separate question, I know you guys don't really want to say how much acreage you've got in some of these other oil plays. I was just curious how many different oil plays you guys -- like including the Eagle Ford, and the Heath, are there any plays that you guys have already accumulated acreage on?

Well, we -- yes. And in the Heath, I think you can probably narrow it down, we're over 100,000 acres in the Heath.

Okay. Great, guys. Thanks.

Okay, Brian. Thank you.

Your next question is from the line of Ken Carroll with Johnson Rice.

Hi, guys. Good morning.

Good morning, Ken.

Just a quick question, back on the Eagle Ford well, in terms of the lateral length of 3,000 feet seems to be maybe a little shorter than we've seen out of some other players. Are your plans for the additional four wells to push lateral length a little bit? Or how do you see that going forward?

Well, yes, we -- this is just our initial roll at it. As Matt had indicated, we went down, we did some coring in this particular well, we've done some science. We wanted to just get our initial test, initial evaluation out there, you know, as the other individuals asking questions, talked about, where you land the well, is it in the lower Eagle Ford, is it in the upper Eagle Ford, all of those things that will be looked at as we move forward.

Okay. Got you. But you would -- it sounds like you would hope to maybe extend that in lateral length a little bit as you just work through the program?

Yes, absolutely.

Very good. Thanks, gentlemen.

Thank you.

Your next question is from the line of Steve Ives with Cheyenne Petroleum.

Yes, on your Eagle Ford well that you announced, what kind of frac materials, what kind of frac technique did you use, and are you going to, like this prior caller, are you still going to be tinkering with that, too, as you go ahead?

We will be. The frac procedure there was basically just white sand. The blue, as we went to a cross-link. And we're still tinkering with our designs and what we will be doing with future wells.

Okay. All right. Thank you.

You have a follow-up question from the line of Jack Aydin.

Dan, you mentioned you had 18 wells in different stages of completion. Can you tell me how many of those are vertical and how many horizontal?

Now, the next question for you is this. Let's just assume half of them are horizontal, and if the 30-day average is running about 8 million, you've got huge backlog of production that is coming up. Could you care to comment on that? And I have one other question to ask.

Okay. Of the 18 wells, 15 of those are horizontal. And three of those are vertical. And --

I could do the math, the rest of the math.

I knew you would circle back around, Jack.

The next question I have is this, I am looking at your 10-K year-end. You've got about close to 200,000 gross acres in Montana. Is that the Heath or it is different formation or different kind of clay? Could you make comment on it?

Well, Jack, I would be disappointed if Mike didn't make one more comment to you before he walks out.

Okay.

Jack?

Yes.

That's that Stealth Oil play.

Oh, that's the Stealth Oil play, okay.

Now -- but no, it is looking at that Heath in central Montana, and obviously, you all picked it up, the acreage in the K. So we will lift our skirts a little bit on that. But yes, we're looking at the Heath as an oil target in that part of the world.

Do you have something (inaudible) to the Niobrara, too?

Do we have a position in the Niobrara?

Yes.

No, sir.

Okay.

No.

Thanks.

You bet.

Thank you, Jack.

There are no further questions at this time.

Presenters, do you have any closing remarks?

Well, thank you, Tiffany.

And again, I appreciate all of the questions. As you can see, by the questions, the Eagle Ford certainly has garnered a lot of attention. I think both with the Eagle Ford, our Haynesville, Shell, and the Bossier opportunities, along with a ramped-up opportunity in the Marcellus and the Lathrop station coming online, towards the latter part of this month, I think next quarter, you're going to see a different production profile with Cabot and we're looking forward to announcing that.

Thank you all for your attention and interest in Cabot.

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