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Cabot Oil & Gas Corp. (NYSE:COG)

Q1 2010 Earnings Call

April 29, 2010; 9:30 am ET

Executives

Dan Dinges - Chairman of the Board, President and CEO

Mike Walen - SVP, COO

Analysts

Brian Lively - Tudor Pickering Holt

Brian Singer - Goldman Sachs

Jack Aydin - Keybanc

Ellen Hannan - Weeden & Co.

Michael Hall - Wells Fargo

Gil Yang - Banc of America

Marshall Carver - Capital One Southcoast

Ronny Eisemann - JPMorgan

Biju Perincheril - Jefferies and Company

Ray Deacon - Pritchard Capital

Brian Kuzma - Weiss Multi-Strategy

Ken Carroll - Johnson Rice

Operator

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. 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).

Thank you. 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.

Dan Dinges

Thank you, Tiffany, and good morning. Thank you for joining us for Cabot's first quarter teleconference call. With me today are several members or our management team including Mike Walen, Scott Schroeder, Jeff Hutton, and Mat Reid, our BP 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 are certainly going to miss you.

Before we start, let me say the standard border plate language and forward-looking statements included in the press releases applied in my comments today. We have many things to cover and expand on from the two press releases that we issued last night. I 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 financial results Cabot Oil & Gas reported financial results last night that exceeded consensus expectations, However lower 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. On the balance sheet our debt level increased to $110 million from yearend to $915 million as we established a sizeable 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 yearend call, we will 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 at yearend 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, let me expand on the operations release. We have numerous wells that strengthen our position in core areas in the Marcellus, in Haynesville and the Pettit. So we also have our best well in the Cotton Valley Taylor sand, confirming a good rate of return project in Minden and we also had 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 3000 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 approximately 300 to 350 potential locations and a resource potential of 60 million to 140 million Boe.

A second company operated well as 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've had initial success and the concept was significantly reinforced by recent peer presentation along trends 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 Pettit Oil program. In the Haynesville as previously announced Cabot has successfully drilled and completed its first Haynesville well. The King number one 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 a 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 long, 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 an additional operated well that has been drilled and cased. We have 29% of this well and we are 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 are encouraged by the Haynesville wells with the high initial rates and certainly excellent recoverable reserves and we are particularly excited about the middle Bossier potential on our acreage in Shelby in St. Augustine County.

Moving to the Pettit. In our Pettit oil play in this area the Warsham Oil number one and the Warsham Oil Unit B number one were stimulated with 10 and 14 stages in the lateral lengths of 5500 feet and 5471 feet respectively. The Warsham Unit A number 1 is currently flowing back. The Warsham Unit B number 1 produced at initial rates 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 have been drilled and completed, one well is waiting on completion and 8 wells remained 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 and natural gas, we look to drill more Pettit, which has the added value of holding our developed 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. Moving up to Minden our third Cotton Valley Taylor of horizontal well has been successfully drilled and completed. The Birdwell (inaudible), a 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 in the first two horizontal Cotton Valley Taylor sand wells that we drilled; they had initial rates of 9.5 and 8.9 million cubic foot equivalent per day. These wells continue to provide superior economics 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 think of more opportune time to drill more tailored wells and the returns are very compelling. Now let's move to the north of Marcellus. Obviously 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've 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 acreage. 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 2 which is the compressor start up phase is well underway with the compressors and dehigh 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 the 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.

We recently drilled and cased our longest collateral well to-date at 5,000 feet. We drilled our first well in 17 days from spud to rig release and that well had 4,300 foot lateral and lastly we completed a 15 stage frac that went into line at 14.6 million cubic foot per day and 1730 pounds location pressure.

This well was curtailed due to current sales point capacity limits as we've discussed and it's been flowing less than 30 days so it was not included in the population highlighted in the press release. With 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 thorough transportation agreements. You will recall that we announced in our last operational update the 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 hence 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 liquid guides 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 leasing success the potential $65 million wedge should be added. Additionally, we continue to look for good leasing opportunities in our core areas.

I am very excited about our program that we have out in front of us in the regions. As you can see we are flush with opportunities, good rate of return opportunities for years to come. Additionally we have several other ancient projects that are in its early stages of evaluation. Stephanie with that I'll be more than happy to answer any questions the group has.

Question-and-Answer Session

Operator

(Operator Instructions). Your first question comes from the line of Brian Lively with Tudor Pickering Holt.

Brian Lively - Tudor Pickering Holt

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

Dan Dinges

Well we didn't have any Haynesville production in the early guidance and now we are rolling but we had very little, now we're rolling in a little bit of the Haynesville but second quarter, we're going to be somewhat limited on the Haynesville production just trying to get the frac crews, the pumping crews in there. You know when you are not an operator that has lying down multiple wells out in front of us, so its hard to stage in there so what we are doing is having a thick windows of opportunity to be able to bring those frac crews in.

Brian Lively - Tudor Pickering Holt

Okay so the production growth in it I take it is largely related to the Marcellus and is that related to the increasing infrastructure with the second phase.

Dan Dinges

Yes the free flowing gas that we are able to put through there most recently and that's just basically us putting the wells directly into the Tennessee pipeline and bucking the 1,000 pounds pressure in that pipeline and additional is going to be once we start cracking up the compressors which should be later next month.

Brian Lively - Tudor Pickering Holt

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

Dan Dinges

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

Brian Lively - Tudor Pickering Holt

Okay and switching over to the Eagle Ford. Some operators have talked about completing wells in the upper Eagle Ford and possibly fracking into the chalk, others talked about completing in the lower Eagle Ford. Could you give some more color on what's your completion practice is today and kind of expectations going forward.

Dan Dinges

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 charts although obviously it depends on how much fracture growth you do get, that you might access the chalk anyway.

Brian Lively - Tudor Pickering Holt

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's correct then what is the kind of current rate, how is the well performing?

Dan Dinges

It's performing very well. It's still producing around 225 - 250 barrels a day.

Operator

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

Brian Singer - Goldman Sachs

Couple of questions on the Eagle Ford, can you just talk about the potential outcomes and the strategy assuming the next couple of wells do work, where are you kind of from infrastructure perspectives and how significant do you think this could be looking ahead to 2011 and that's may be the first part and the second part is if you do accelerate activity in the Eagle Ford beyond these next few wells, would you think of that as additive to your CapEx or would you pull some activity down somewhere else in the portfolio?

Dan Dinges

Yeah first of we have leases down there that we have taken say within this last year and our primary term expiration and (inaudible) 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 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've 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, this is something we do on a daily basis and we would look at how we can get our arms around all 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.

Brian Singer - Goldman Sachs

And so I guess when we think about from a natural gas drilling perspectives outside of the Marcellus so you're essentially drilling the minimum levels of the whole acreage across the portfolio i.e. if gas prices stay 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's not a lot of room to reduce from here with that acreage expiration.

Dan Dinges

Yeah, we have that's correct. We have laid out a program out in front of us that allows us to capture our acreage but 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 (inaudible) cotton valley well we drilled, horizontal well. That particular well has excellent economics and the returns are ever been as good as what we're seeing in the Haynesville but we have elected not to drill any additional wells out there but that acreage is HBP.

Brian Singer - Goldman Sachs

One last one, if there is anything unique to the particularly Eagle Ford location and a portion within your acreage that you think would make it either a more significant or less significant versus other wells you expect to drill.

Dan Dinges

No its just going to be an area that we had focused on early on, we've bought some leases in this area, where some of our early acquired leases, how we started moving forward and getting our meds and getting land up in locations so that in all in one of our early area leasing and that's where we drill our first well but other than that nothing unique to where we pick the location.

Operator

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

Jack Aydin - Keybanc

Dan regarding the Eagle Ford, what kind of a decline you're seeing. I know it's the first well. What kind of decline you are seeing. Second, I know you saw numbers about 60 million to 140 million and also you give a little bit of the number of wells so you're talking about in a way its basing somewhere in excess of 140 acres per well, could you elaborate a little bit more on that?

Dan Dinges

Okay well 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 EUR, they had anticipated flow rates and our acreage is exactly on trend with that peer, that laid all those out. So versus kind of going over the redoing the presentation that's out there that had considerable detail, we agree with that presentation.

Jack Aydin - Keybanc

I have it in front of me. Okay all right thanks a lot.

Operator

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

Ellen Hannan - Weeden & Co.

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 I am going may be covering some ground again but how many wells do you think you will need to HPP your acreage in terms of how you were able to kind of lock it up and secondly, have you run into a situation there where you had to lease the water rights separately from the mineral rights?

Dan Dinges

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

Ellen Hannan - Weeden & Co.

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

Dan Dinges

Not really Ellen, these newer wells we've kind of moved to the eastern side of our acreage block and we are getting some excellent results coming forward now and I think that we'll stamp out with our reserve estimate there.

Operator

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

Michael Hall - Wells Fargo

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?

Dan Dinges

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

Michael Hall - Wells Fargo

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?

Dan Dinges

Are you talking about the in the Eagle Ford?

Michael Hall - Wells Fargo

Yes

Dan Dinges

Well there is a couple of things I'll turn it over to Jeff our VP in marketing. I know 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 the projects down there.

Jeff Hutton

I'll concur with Dan and might add that to date we've not added any hauling issues. Obviously there is a lot of activity but I think the industry is good enough to make sure and everything that is...

Michael Hall - Wells Fargo

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

Dan Dinges

Right and keep in mind we have our focus primarily with capital allocation going to Marcellus and also primary term maintenance and primary term capture in the Haynesville/Bossier, our first well in the Eagle Ford was successful, I think we will gain efficiencies of our completion techniques in the subsequent wells but we have not put together a large expensive program in the Eagle Ford at this time with the number of wells that we we're talking about. So initially Michael we are going to be trucking our rollout initially and contemporaneously working on expansion of our program and other opportunities for our transportation.

Michael Hall - Wells Fargo

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?

Dan Dinges

Let me turn it over to Matt Reid?

Matt Reid

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

Michael Hall - Wells Fargo

And then 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.

Matt Reid

Yes, but small about amount.

Michael Hall - Wells Fargo

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…

Matt Reid

Let's not (inaudible) as remember there is only four wells for the total year program at this point in time too.

Michael Hall - Wells Fargo

Fair enough. And then last one, quickly, on acreage additions you had in the release, upwards 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?

Dan Dinges

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 we are still active in our area of such quantum and where we do have active leasing programs, we are not willing to discuss what we are paying (inaudible)

Michael Hall - Wells Fargo

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?

Dan Dinges

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 were to have looked at this eight months ago, 10 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 have continued to expand and we continue to improve our initiatives up there are long and laterals, more fracs and quicker drill rates and efficiencies.

We have just overtaken the timeframe of our infrastructure in start up date and which is a high class problem, again we anticipate us putting a significant volume of gas into the Lathrop station once we can crank up the three compressors on side and initially I might add the initial phase which is, while we are calling a second phase is to start-up the compressors, we have three compressors that we'll be starting up early on. That will be about 65 million cubic foot of additional capacity and then towards middle of the summer we'll 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 its going to be our intent to fill that in capacity as quickly as we can

Operator

Your next question is from the line of Gil Yang with Banc of America

Gil Yang - 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?

Dan Dinges

You are talking about getting the funding equipment to the location?

Gil Yang - Banc of America

Right.

Matt Reid

Well we're seeing since (inaudible) we don't have a major program up there like many of the other operators. We have to get in the queue and take data we can get on. We try and schedule our fracs to two and three months in advance in a big time period between two and three weeks. Right now we are scheduled about two months out from end of the drilling and completion right now so.

Gil Yang - Banc of America

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

Matt Reid

We do not, that's correct

Dan Dinges

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

Gil Yang - Banc of America

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?

Dan Dinges

Well our guidance has taken in consideration our full year program as we've 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 big success, we might even be above it.

Gil Yang - Banc of America

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?

Dan Dinges

We are interlaced with the other operators.

Gil Yang - Banc of America

Okay. In the well that you reported, based on what the other operators seem to be reporting, well, 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 get to the same results they have?

Dan Dinges

Oh Gil, yeah, 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've seen other first efforts out there and I think early time data that we see our will is very consistent and overlay of the early time that we've seen in peer wells out in the area and again 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's been discussed out there by others.

Operator

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

Marshall Carver - Capital One Southcoast

Yes, it's 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?

Dan Dinges

On Marcellus, those would be in the range between about 2,800 to 3,800 foot something in that order. Not many of those are the long reached laterals yet.

Marshall Carver - Capital One Southcoast

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…

Mike Walen

The 334 rate was the IP rate.

Marshall Carver - Capital One Southcoast

Okay.

Mike Walen

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.

Marshall Carver - Capital One Southcoast

Right. And how long has the well been online?

Matt Reid

Online roughly 30 days and a little longer.

Marshall Carver - Capital One Southcoast

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?

Matt Reid

Our locations in the Taylor horizontal was roughly 40-50, since our locations.

Operator

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

Ronny Eisemann - JPMorgan

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

Operator

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

Biju Perincheril - Jefferies and Company

Thanks, good morning. Dan, 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 permit.

Dan Dinges

We do that, they're all government in hand and now and we're continuing to light pipe out there and we'll continue to secure additional permitting but we just a – we just had a period in there where we had a delay.

Mike Walen

Yes, yes. Biju what is that permit was a kind of one-off deal. We generally blow all of the streams so we don't have to get permit across it. In this one case, the boring did work and we had to go back and get a an actual physical stream crossing and that's why it took so long and delay enough of that one piece of bite. But our standard operating procedures is to abort the wetland and keep away from the permit process.

Biju Perincheril - Jefferies and Company

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

Mike Walen

We do anticipate having to have more stream crossing, stream crossing permits. Like as I said, that isn't something that we go forward looking to do, it's only if we have some issue on this physically boring the rock like we did in this one case.

Biju Perincheril - Jefferies and Company

Okay. Got it.

Dan Dinges

And the other thing is that we're getting more wells spread out and not all depended upon just eight pipeline in this particular case that Mike talked about. We had a couple of fresh wells so we had drilled completed, we had in our forecast and with our forecast number being a smaller number did affect our expectations. Now getting a bit diverse spread of wells that are coming in from different areas and not all dependent upon A-pipeline or A-borrowing that would, that I have hoped we are not significantly delay any production expectations.

Biju Perincheril - Jefferies and Company

Okay. Perfect. And the Eagle Ford well, did you ever disclose what the cost on the first well was?

Matt Reid

The average cost this well which is deeper in sports [ph] and deeper potential. But on average cost it is going to vary somewhere between the higher 4 million 5.5 million.

Biju Perincheril - Jefferies and Company

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?

Dan Dinges

Biju I am not really following the question.

Biju Perincheril - Jefferies and Company

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

Dan Dinges

This particular well its kind of in the middle.

Biju Perincheril - Jefferies and Company

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?

Dan Dinges

Well we share a little our looking at a five year company wide program I've discussed earlier the five year actually 10 year program we are developing in the Marcellus area we are also putting together company wise five year program that again is going to be pretty dynamic document. But it is our intent in balancing with capturing our primary term average to add this commodity price environment more old more liquid to production profile. The one thing that would be of not if you look at it from a percentage perspective though the ramp up that we are 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 liquids. We think that's going to go up from this point onward.

Biju Perincheril - Jefferies and Company

How much acreage you have to the heat?

Dan Dinges

What's the I don't think we put that after yet.

Operator

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

Ray Deacon - 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?

Dan Dinges

We do, I don't we get any of debt.

Ray Deacon - Pritchard Capital

Okay. I got well costs you gave, anyways.

Dan Dinges

Yeah

Ray Deacon - Pritchard Capital

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?

Dan Dinges

Well you know we are I know we are getting efficient on our drilling up there for example, last where we drilled was from Spad to rig release was 17 days and we just made a trip up there. Yesterday our entire board meeting and Pittsburgh and our new office up there. Our entire board wanted to visit our subsequent operation and evaluate our progress up there under the safety environmental committee of our board. We carried in 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 show-and-tell 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 maybe reflective and also the timing of some of our operation.

Ray Deacon - Pritchard Capital

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. Does it look like it is not going to affect permitting going forward?

Dan Dinges

One thing you have to keep in mind that is just factual that we have an area that we are 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 this area calls 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 and we are not having 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 have 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 and mitigating any concerns of surface exposures environment risk and the cementing and casing operations that we implemented 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 regulation and expectations from this point forward.

Ray Deacon - Pritchard Capital

Is the Eagle Ford well on pump after a month, or not?

Dan Dinges

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

Operator

The next question is from the line Brian Kuzma with Weiss Multi-Strategy.

Brian Kuzma - Weiss Multi-Strategy

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

Dan Dinges

I know we are ramping up and we have been kind of up and down as we have been working with some of that free flow gas in the Lathrop station, but probably say 95 million to 100 million a day would be a good number?

Brian Kuzma - Weiss Multi-Strategy

And that's the net number or the gross number?

Dan Dinges

It would be the gross number.

Brian Kuzma - Weiss Multi-Strategy

These wells that are 8 million a day, on the 30-day rate, that is clearly ahead of your type curve, what happens as 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, if you kind of knocked out the infrastructure?

Dan Dinges

We are very pleased obviously with the results that we are getting and we are excited about our new initiatives and what we have 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 side. 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 have announced signing up some additional firms.

So we are making every effort to stay out in front of our production. Again Lathrop station is a fairly significant station. We were up there by that station yesterday with our board and it's coming along very well and three compressors on-site, [dehigh], that all up right now. We have already pored 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 and could possibly get that particular compressor site location up over 200 million cubic foot per day. We are doing things, scrambling and using all the technical resource and certainly pushing our guys and they are doing a great job, getting this thing strung up.

Mike Walen

Another issue that of course out there building a lot of compression, but this is a dry gas pipeline quality gas, so we are not having to strip liquids and that a big positive for getting these wells online timely.

Brian Kuzma - Weiss Multi-Strategy

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

Dan Dinges

Well we have a multi-tier options that we are 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 are running dual tracks, 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 with that extensions how much acreage we capture and then making the decision that if we do extent some of that primary term acreage into another 5 year term or so, does that give us the flexibility to slow down some of our drilling? We are trying to look at all of that as we go forward.

Brian Kuzma - Weiss Multi-Strategy

So on the compressor side, you will have 110 at Teal, 165 at Lathrop after the summer, and then these other projects that you're talking about, roughly when would they come online and, again, what size would those be?

Dan Dinges

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

Brian Kuzma - Weiss Multi-Strategy

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?

Dan Dinges

Yes and in the Heath, I think you can probably note it down; we are over 100,000 acres in the Heath.

Operator

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

Ken Carroll - Johnson Rice

Just a quick question, back on the Eagle Ford well, in terms of the lateral length of 3,000 feet seems to be a little shorter than we've seen 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?

Dan Dinges

This is just our initial role at it, as Matt had indicated, we went down, we did some coring in this particular well. We have done some science; we wanted to just get our initial tests, initial evaluation out there 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 those things that will be looked at as we move forward.

Ken Carroll - Johnson Rice

It sounds like you would hope to be extend the lateral a little bit as you just work through the program.

Dan Dinges

Yeah, absolutely.

Operator

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

Unidentified Analyst

Yes, on your Eagle Ford well 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?

Matt Reid

The frac procedure there was basically just white sand. The blue, is we is we went to a cross link, we're still tinkering with our designs and what we'll be doing with the future wells.

Operator

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

Jack Aydin - KeyBanc

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.

Dan Dinges

Okay, of the 18 wells, 15 of those are horizontal and three of those are vertical.

Jack Aydin - KeyBanc

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

Dan Dinges

I know you circle back around Jack.

Jack Aydin - KeyBanc

I am looking at your 10-K yearend. You've got about close to 200,000 gross takers in Montana. Is that the Heath or is it different formation or different kind of play? Could you comment on it?

Dan Dinges

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

Mike Walen

Jack?

Jack Aydin - KeyBanc

Yes.

Mike Walen

That's had stealth oil play.

Jack Aydin - KeyBanc

Oh, that's the stealth oil play, okay.

Mike Walen

But no. It is looking at that Heath in Central Montana and obviously you all picked it up, the acreage in the case. So will lift our spirits a little bit on that. Yeah, we're looking at the Heath as an oil target in that part of the world.

Jack Aydin - KeyBanc

Do you have something in the Nibora there too?

Mike Walen

Do we have that position in the Nibora? No, sir.

Operator

There are no further question at this time. Presenters, do you have closing remarks?

Dan Dinges

Thank you, Tiffany. Again I appreciate all 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 and Haynesville shale and the Bossier opportunities along with a ramped up opportunity in the Marcellus and the Larthrop Station coming on line towards the latter part of this month. Next quarter, you are going to see a different production profile with Cabot and we' looking forward to announcing that. Thank you all for your attention and interest in Cabot.

Operator

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

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Source: Cabot Oil & Gas Corp. Q1 2010 Earnings Call Transcript
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