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Cabot Oil & Gas (NYSE:COG)

Q4 2010 Earnings Call

February 23, 2011 9:30 am ET

Executives

Scott Schroeder - Chief Financial Officer and Vice President

Jeffrey Hutton - Vice President of Marketing

Dan Dinges - Chairman, Chief Executive Officer, President and Member of Executive Committee

Analysts

Michael Hall

Brian Singer - Goldman Sachs Group Inc.

Joseph Magner - Macquarie Research

Robert Christensen - Buckingham Research Group, Inc.

Jack Aydin - KeyBanc Capital Markets Inc.

Biju Perincheril - Jefferies & Company, Inc.

Raymond Deacon - Pritchard Capital Partners, LLC

Gil Yang - BofA Merrill Lynch

Amir Arif - Stifel, Nicolaus & Co., Inc.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

Operator

Ladies and gentlemen, thank you for standing by, and welcome to the Cabot Oil & Gas Fourth Quarter 2010 and Year-End Conference Call [Operator Instructions] I would now like to turn the conference over to Dan Dinges, Chairman, President and CEO.

Dan Dinges

Thank you, Beverly, and good morning. I appreciate everybody joining us for this year-end teleconference call. I have with me today Scott Schroeder, Jeff Hutton, Matt Reid, our VP and Regional Manager of South; and our newly elected VP of Engineering and Technology, Steve Lindeman. I want to state that the boilerplate language, forward-looking statements included on the press release do apply to my comments today.

At this time, we have several things to cover and expand on from the three press releases that were issued last night. I will briefly cover the year-end financial results, the year-end reserve metrics and then on a more detailed discussion of our operations including our plans for 2011. I'll be brief and allow time for Q&A at the end.

Cabot did report its financial results for the year with earnings of just over $100 million and with cash flow from operations of $485 million. The company maintained our strong financial structure, raising over $200 million through asset sales in the fourth quarter to reduce debt and create more flexibility with capitalization ratio of 32%. From a clean earnings perspective, net income was basically the same as reported with selected items, which include gain on sale, impairments, stock compensation and a true-up of deferred taxes that net out.

Fourth quarter clean earnings were $20 million on the strength of record production levels. We do not normalize cash flow, both the quarter and the year were impacted by the cash taxes associated with the gains from the fourth quarter asset sales. This had approximately a $25 million to $30 million lowering effect on reported cash flow. However, I'd gladly take the $211 million pretax proceeds we raised in exchange.

From a value-added perspective, as we all know, a key metric to an organization's growth and value creation is its ability to stack up reserves at economic investment levels. Cabot once again accomplished that by growing reserves a record 31% year-over-year to a new established high of 2.7 Tcfe. Not only is this record performance impressive, it is equally noteworthy that we held our PUD level at 36%, the same percentage reported at the end of 2009. This booking translates into a proved developed reserve increase of 30%.

The value from this program has created for Cabot shareholders, as illustrated by the fact with only 13% increase in year-end SEC gas prices, Cabot realized a 100% increase in its SEC PV 10 to $3.2 billion. That is a good demonstration of value creation year-over-year. The company was able to add 651 Bcfe before production and revision adjustments for the year. This compares to 463 Bcfe added last year. With all of the 2010 increase coming from our organic drilling program, the corresponding all-source finding cost was $1.05 per Mcfe, a level not seen since 2002 when we had roughly a $100 million program. Excluding lease acts, this figure drops to $0.89 an Mcfe. The company replaced 603% of its production through organic growth at a very efficient finding cost.

As I mentioned a minute ago, Cabot once again managed its PUD portfolio for compliance with the five-year SEC rule. We look at our PUD profile as a balancing act with future capital needs, finding cost metrics over the long term and a realistic assessment of how much PUD drilling is prudent to execute in our program over the next several years. In light of the current natural gas strip, the dynamics of our Marcellus program and the South Region's oil program, we removed PUDs from our conventional inventory in West Virginia, Rocky Mountains, Mid-Continent, South Texas and East Texas. This high graded our overall PUD portfolio, which now only has 620 total locations, down from 948 at the end of 2009. All these PUDs can be drilled easily with anticipated cash flow. Even with this reclassification of P2 from PUD, the performance revisions from our Marcellus program provided us with an overall positive revision of approximately 137 Bcfe. Our investment program during the year for total finding cost purposes totaled $828 million, which included $131 million for new leases in the Marcellus and the Eagle Ford.

In terms of production, the company reached a milestone with a full year production number of 130.6 Bcfe, exceeding the high end of our full year expectation of 25% production growth. Our actual growth was 26.8% increase. This record-setting performance was achieved even after the restricted rates due to the slowdown related to the Lathrop compression station Phase II permitting approval process. I'll have additional comments on our Phase II work once I get to the North region.

Guidance last night, we posted full year 2011 guidance. This range results in an overall growth rate of 30% to 36%. Specifically, the growth in natural gas volumes is targeted at 30% to 35%, while our South region emphasis on oil for their entire program is expected to pay dividends with liquid growth of about 30% to 70%. The range of growth is dependent upon the timing of our completions.

So my fearless guidance is a conservative based on our reserve release and the dynamics of our 2010 program. However, today, there is over 1.2 Bcf per day flowing into the Tennessee 300 line from ourselves and our peers in the Three County area in Northeast PA. Until our initiatives to move gas through other pipes are complete, and that's a strategy we implemented over a year ago, we're going to be comfortable with this guidance. Our conservative approach assumes this dynamic is clarified by the start of the fourth quarter with three new construction and expansion projects scheduled for completion. These projects include a 33-mile high-pressure 24-inch pipeline from our Lathrop station to Transco interstate pipeline; a 35-mile 16-inch high-pressure pipeline that will connect our northern acreage position with Millenium interstate pipeline and the expansion of the Stagecoach Lateral designed to move gas out of our core area also to the Millennium line.

Okay, our operations plans for 2011 have remained unchanged from our original budget. We're holding firm to our $600 million capital program that has $350 million directed towards the North region for the Marcellus and $250 million in the South region for the Eagle Ford oil initiative. Cabot did take advantage of a short window of opportunity for natural gas price strength during the first quarter and hedged approximately 150 million cubic foot of production, which was hedged at a mark north of $5. And that is for all of the remainder of 2011 and all of 2012. This effort combined with the previous position has us 36% hedged in 2011 based on the midpoint equivalent guidance. We also have a good job north of $5 for 2012.

In the North region, our Marcellus area as you saw in the press releases continues to excel, achieving a new production record of 265 million cubic foot gross per day, predominantly from 51 horizontal wells with production growth an impressive rate of 36% over our third quarter of 2010. Cabot continues to have great success as demonstrated by one of our recent completions that had an IP of over 23 million cubic foot per day and a 30-day average of approximately 19 million cubic foot per day from a 3,700-foot lateral. Other recent 30-day averages include a 14 million per day and 10 million per day from several shorter lateral wells. We also just finished drilling a 6,100-plus usable lateral, which is another record for us. We plan to complete this well with a 26-stage frac. In addition, we recently had a well achieve three Bcf key in production in just eight months from a 15-stage completion, which is also a record on the key in production number in that short period of time. The well is currently still producing 9 million a day. These statistics highlight the prolific nature of this area of Marcellus where Cabot's acreage is located.

Based on these statistics and while still continuing to enhance our completion techniques, we have conservatively booked 6.5 Bcf EUR for our PUDs in the area, which assumes a well with approximately 10-stage frac. However, we have a growing population of wells that are expected to produce 10 Bcf plus. And as we get more data, we will continue to assess our reserve bookings. Cabot is currently running five rigs in the Marcellus and our plan is to drill around 50 horizontal wells during 2011. Today, Cabot has 34 stages being completed, 107 stages waiting on pipeline and 450 stages waiting on completion.

At the Lathrop Compressor Station, which now is owned by Williams, they have received all the required permits to run an additional four compressors at the station, which will give the station a total of seven compressors. With the startup of the fourth compressor, which we're currently commissioning, the capacity of Lathrop will be at 250 million cubic foot per day when units five, six and seven become operational. Along with the necessary additional dehydration, Williams will increase the capacity of the station potentially reaching a total of 450 million cubic foot per day. Again, actual flowing ability will be tied to the interstate take-away capacity and the completion of the William Springville line from Lathrop to Transco, which is expected to be operational in the third quarter.

In the Rocky Mountain area of the North region, Cabot has drilled and cased a Montana horizontal lock at located in the Heath play. We expect to complete this well in the second quarter of this year. We have over 100,000 acres in the play.

Now moving down to the South region, which we're going to allocate all of our $250 million to the Eagle Ford. The company had successfully completed its fourth Eagle Ford well. It's a 100% well located in the South county. It was drilled to a total depth of over 14,800 feet and had over a 5,900-foot lateral. The well was tested and flowed on a maximum 24-hour rate of 789 barrels of oil equivalent a day. This well is located in our Buckhorn area. The fifth company-operated well, also 100% Cabot, is located in Frio County also in the Buckhorn area, was drilled with a lateral of over 6,700 feet and is presently being completed. Two additional wells have been drilled and cased in the Buckhorn area and will be completed in late February and March.

Additionally, our 18,000-acre area of mutual interest with EOG Resources, the first well has been drilled and cased. This well was drilled with over a 7,000-foot lateral and is presently on flowback after completion operations. Cabot intends to drill or participate in 20 net Eagle Ford oil wells in 2011. Also to ensure timely completion of the Cabot-operated wells, the company has executed an agreement for a dedicated frac crew for 2011 for these operations.

Moving to East Texas and a comment in regard to our East Texas joint venture. Cabot is finalizing agreements that would allow Cabot to maintain a large percentage of a changeable acreage with no capital investment. These agreements will provide Cabot with a carried interest on the initial well for 25 units. If commodity prices remain at similar levels we're seeing today and the acreage held by the initial wells in the units, no subsequent drilling would occur in these units for a period of time. Additionally, the negotiations include the sale of a minority interest in 34 non-operated units, both producing and nonproducing with net production to Cabot of approximately 4 million cubic foot per day. When executed, these agreements will allow Cabot to maintain approximately 22,000 net acres of its original 33,000 net acres in the play.

In closing, Cabot's operational program is, quite frankly, fairly simple. We'll spend $350 million in the best area the industry has discovered in the Marcellus. And we will deliver significant returns with, I think, stellar reserve and production growth. Also, we will allocate $250 million in the oil window of the Eagle Ford, which will increase our oil reserves and will increase our oil production between 30% and 70% year-over-year. So in Cabot, you have the best rate of return gas project in North America, which I concludes a rate of return comparison to many oil projects. And the remainder of our capital is allocated to a good rate of return project in the Eagle Ford.

That really with those comments, I will now turn it back to you to see if there's any questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Brian Lively.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

Just on the 6.5 Bcf PUD bookings with respect to the 10 Bcf booked on the PDP wells. Just curious, are those conservative numbers just based on repeatability of the wells? Or are there some other concerns potentially about depletion considering the outside success from your early well?

Dan Dinges

Not a problem at all with depletion, not concerned about that at all. We had a geographic consideration on the length of laterals that we'd be drilling with future PUDs that we recognized the exact size of each unit. And so from a conservative standpoint, we elected to say, okay, let's assume that we averaged plus or minus 10 stages per well, and with not knowing exactly the full lateral length of each well because of the acreage considerations. So with that in the database we have, we recognized the 6.5 Bcf PUD booking.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

But even if you take the smaller laterals and you're average is 6.5 Bs, what would you guys estimate as the 2P reserves per well for that lateral well?

Dan Dinges

Probably be a little bit north of there.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

What degree of production data would you need to see from your program, I guess in 2011, to increase the guidance EURs per well and would that be reflected in the CapEx and volume estimates?

Dan Dinges

I think we'll have, again with these longer laterals and our longer laterals and increased number of stages per well, once we get a year of say, production data behind us, we see the curve fit by that production. I think we'll, at that point in time Brian, will be comfortable of maybe making a little bit more robust recognition of what we're hopeful to see.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

I noticed that the gas volumes are flattish in the second half of 2011, understandably for infrastructure-type uncertainties. But just wondering why liquids also appeared to be flattish during the second half of 2011?

Scott Schroeder

Again, Brian, this is Scott. We're taking a conservative approach. It's based on, as Dan made in his comments, the timing. As we emphasize this kind of 30% to 70% growth on those liquid volumes. And so we've taken a conservative stand based on the timing of the completions. The other thing we've had challenge us in the last, say, three quarters is we've come up slightly lower than our guidance. And we want to get that calibrated correctly before we ramp that to any great degree.

Dan Dinges

Brian, I might add also in the South region, not unlike what we're seeing in the North region, there is a lot of infrastructure that needs to be in place out there also. And from the number of trucks hauling oil right now and the timing of getting some of that take-away infrastructure capacity in place, we were a little bit conservative on that year-end guidance on liquids.

Operator

Your next question comes from the line of Brian Singer.

Brian Singer - Goldman Sachs Group Inc.

Following up on the last one, can you give us your latest thoughts on the timing of Laser Williams Stagecoach and with are there any other [ph] trainings out there that would prevent you from ramping volumes up to your full allocated capacity when those pipelines do come up?

Dan Dinges

I'll let -- Jeff Hutton is here. And Jeff has been intimately involved with the negotiations and the transfer and transition to Williams. And I'll let him update us on that.

Jeffrey Hutton

Brian, the Springville pipeline that’s going to connect Lathrop with Transco, it's under construction. Their timing on the key Bolder Call last week, their timing is still July, maybe the end of July. So we're not far from agreeing with that. But again, they're under construction. With Laser, that's another pipeline warrant to Millennium. That pipeline is also under construction, which means they have the permits and they have their crews out there. And we anticipate them to be approximately the same schedule as Williams. The Stagecoach Lateral is a little bit per annum because you can have the interstate Tennessee line that Cabot already holds capacity on, that connects the Stagecoach Lateral. That's anticipated to be in November. And last time I checked, they were right on schedule. They do not have a construction pipeline project to complete, only a compressor station. So everything looks good.

Dan Dinges

And Brian, I might add that in our guidance, we have allowed for a little bit of time beyond the anticipated completion dates of these projects and the guidance we currently have. As we get closer and we can make the determination that the start-ups will occur maybe sooner than our guidance, then certainly, we'll by all means reflect that.

Brian Singer - Goldman Sachs Group Inc.

And then also on the Marcellus, can you just refresh us on that well spacing assumptions and then over what percent of your acreage in Susquehanna you've drilled that's confirmed in that basin?

Dan Dinges

Well, we think the well spacing right now would be 1,000 feet. And we drilled some 1,000 feet offsets. And we have not drilled wells to evaluate a reduced spacing from that at this stage. But we feel comfortable with where we are so far. And the spacing, we think, could be -- at that would be about 80-acre spacing.

Brian Singer - Goldman Sachs Group Inc.

Lastly on the Heath well, I guess any comments so far ahead of completion? Any reason to be optimistic or pessimistic?

Dan Dinges

No, we did certainly have enough encouragement to continue on with our plans for a completion attempt.

Operator

Your next question comes from the line of Michael Hall.

Michael Hall

Just curious on the 10 Bcf wells for 2010, you had a couple of kind of focus areas in the 2010 program. What was the kind of variation around that 10 Bcf? You're pretty tight and consistent across the different areas you drilled during the year. Is there a meaningful amount of variation? And then how much of your total acreage would you expect that, in theory, could be extrapolated to?

Dan Dinges

Well, from the area that we have drilled, we did not see just a specific point in the area we've been drilling that we recognized 10 Bcf, we had seen some very, very strong wells within the parameter of the areas that we've drilled. We've seen an extremely strong well down at, say a 10 or 12 Bcf well, down to the south of our acreage. The three wells that we mentioned in the press release that pinned almost six Bcf and they're still producing 34 million cubic foot a day. That was kind of to the north of our drilling area. We have a couple of wells to the west of our area that also have seen these wells. Exactly the reason why we're seeing these wells, certainly they added lateral lengths and stages have an impact on it. And from our ability to evaluate our 3D that we have out there right now, we're still early in the game. But we're seeing what kind of effect well placement has by the use of 3D.

Michael Hall

And so if I'm thinking about, you'd say, on the 6.5 Bcf PUD booking at 10 stages at $650 million a stage, is that pretty consistent then with the PDP as well? And really it's just the length of lateral number stages are like? How is that number then risked, if you will?

Dan Dinges

We have seen some consistencies. I don't want to get into a myopically looking at each stage. But from an overall average standpoint and looking now at all the 500-something stages that we have producing right now, it is -- there's a correlation certainly by the amount that we can recognize not only on the EUR booking but also our anticipated production rates. There's certainly a correlation with the number of stages.

Michael Hall

And then how are well costs trending like in the Marcellus as well as the Eagle Ford at this point?

Dan Dinges

The thing you know, it is -- the wells are being drilled very efficiently. The well costs that you're running, drilling the TD and running pipe is now the minimal cost of the well compared to the number of stages. So the number of stages, like a well that we've recognized here, our PUD bookings would be a $5 million to $5.5 million well.

Michael Hall

Okay and what about in the Eagle Ford? They got a 6,000-foot lateral.

Dan Dinges

6,000-foot lateral, we're seeing probably $6.5 million to $7.5 million

Operator

Your next question comes from the line of Amir Arif.

Amir Arif - Stifel, Nicolaus & Co., Inc.

A quick question on as you move from '11 to '12, can you just talk about the take-away, whether it's the Tennessee or the Laser line, do you have take-away capacity sort of firmed up for '12?

Dan Dinges

I'll turn that over to Jeff also and he can kind of run through, not only maybe the bank past due but also some of the things we've done on our marketing efforts.

Jeffrey Hutton

Yes. The way this is laid out for us, the capacity on these pipelines that are being constructed on our behalf, such as the Williams line and the Laser pipeline. Those are all long term. When I say long term, an excess of 15-, 20-year kind of arrangements. It also includes the right for Cabot to extend those to the even longer periods of time. So there's no fear in losing your capacities once these pipelines are constructed. Those are two steps that we've taken to ensure take-away. There's also another aspect of this and that's the long-term take-away agreement that we have on Tennessee Gas Pipeline. Those agreements allow for -- I think, the earliest one expires in five years, and they go out as far as 15 years. But those agreements also allow Cabot a unilateral option to extend those agreements. So for gas, leaning the area to Millenium and Transco, we still are in great shape. For gas, we're going to continue to produce and deliver to Tennessee, we feel like we're in great shape for a long, long time.

Amir Arif - Stifel, Nicolaus & Co., Inc.

And then just a quick question on the Eagle Ford, and I apologize if you've answered this, I hopped on a little late. Can you tell us where the fourth well was? Was that in the Frio county?

Dan Dinges

The fourth well is in LaSalle County. Which is by the way, our Buckhorn area covers kind of what they call a four-county area right there. So it's all kind of part of our Buckhorn prospect.

Amir Arif - Stifel, Nicolaus & Co., Inc.

And most of your remaining 11 Eagle Ford wells, that will all be in that area?

Dan Dinges

The operated wells will be in that area. And the non-operated wells with EOG Resources will be west of there in our AMI area.

Operator

Your next question comes from the line of Ray Deacon.

Raymond Deacon - Pritchard Capital Partners, LLC

Dan, I was wondering if you could elaborate a little bit more of the previous question about the 10 Bcf EURs. I guess how large -- how many acres of the 160,000 do you think that is going to be applicable to you, I guess? Or how much have you kind of de-risked so far?

Dan Dinges

Well, we have recently drilled a well all the way, say eight miles to the outside of our area. And that particular well was logged and evaluated and has not been completed yet. But it looks every bit as good and in some cases, well it looks every bit as good as the wells that we have completed. There's also wells to the North that we've seen or at least are aware of that we feel comfortable with majority of our acreage position, put it that way. There's certainly going to be acreage, Ray, that is -- so gets the periphery that we have not yet evaluated by drilling.

Raymond Deacon - Pritchard Capital Partners, LLC

And I guess I've seen some permitting activity in the Marmot. And then I was wondering if you could talk about whether you're going to be drilling a well there or just keeping an eye on it?

Dan Dinges

Is that in Oklahoma?

Raymond Deacon - Pritchard Capital Partners, LLC

Yes. Exactly, right. I guess Beaver County and then to the South and in Texas also.

Dan Dinges

You're aware that we have a lot of acreage in Oklahoma in the mid-counted area. There's a number of plays that are being look at up there for horizontal oil drilling. And we're evaluating some of those plays. And the Marmotan is one of those plays that we're currently evaluating.

Raymond Deacon - Pritchard Capital Partners, LLC

Do you see any drilling activity this year or mainly just permitting?

Dan Dinges

No, I think we will drill.

Raymond Deacon - Pritchard Capital Partners, LLC

And I guess just to be clear on the take-away side in terms of compression, can you just summarize that? It seems like there's more -- you have more compression capacity than what you were talking about last quarter. Is that a fair comment?

Dan Dinges

Jeff?

Jeffrey Hutton

Sure. Compression is not exact science. In other words, the capacity on compression can be altered or modified based on the raw operating parameters that you want to establish. In other words, to say it simply, if you want to run a higher section pressure, you can get more throughput out of the same horsepower. So it does move around a little bit. But I think one line that's sticks out in the speech today is the Lathrop Compressor Station can run and be modified to operate at around 450 million a day of throughput. When all of the other options, the beehives and the slope captures and everything is modified, then we'll be in good shape come three months or so, so that station's going to operate fully. Is that helpful?

Operator

Your next question comes from the line of Gil Yang.

Gil Yang - BofA Merrill Lynch

I just wanted to clarify the PUD booking a little bit more. 6.5 Bcf for the PUDs and the PDPs were booked at 10. And what are the number stages for the PDPs versus the PUDs?

Dan Dinges

Well, the PDP is, for our 2010 program was various. We had anywhere from nine to 19 stages in the bookings that averaged out at 10 Bcf.

Gil Yang - BofA Merrill Lynch

Do you have an average number of stages? Or you don't have that?

Dan Dinges

Well, yes. It's between, say 12 and 15.

Gil Yang - BofA Merrill Lynch

In your lateral length decisions, what's driving the length that you're deciding to drill those wells?

Dan Dinges

Well, Gil, we've had capacity restraint up there for a number of reasons. But it has mainly dealt with capacity constraints with the compressor station and getting our equity gas out of the field into the interstate pipeline. And when you look at the amount of acreage that we blocked up in Susquehanna, and certainly Cabot has the largest position in Susquehanna, we're trying to affect on trades of our acreage, swaps of our acreage that would allow companies that have a minority position just an acre here, an acre there within our outlined area to us trade acreage with them and allow them to block up where their position is, allow us to block up where our position is, where the dollars that our group spends is allocated 100% to Cabot and the dollars they spend would be allocated 100% to their position. It also holds true with the equity gas that we're moving out of the field. Again, we're not able to move 100% of our equity gas at this period of time. We have a significant present value backlog, if you will, by not being able to produce all of our gas. If we start bringing in third-party gas into this pipeline system, all that does is displace Cabot equity gas and does not allow us to recognize the present value of our investment out there. In early stage, we think it is prudent to be able to use every molecule that is available out there in infrastructure and capacity for Cabot equity gas. We've invested over $1 billion in this county, in Susquehanna County right now, and we are working that return. I think we've got a spectacular return. But nevertheless, we don't have room for all our guests. So that's why the trades are being negotiated, have been executed and we continue moving in, in that regard. Long-winded answer to illustrate to you that in, also in some cases, those negotiations might affect the placement of wells. But also there are holdouts in certain areas and individuals that have acreage that do not want to lease their acreage under any circumstances. And that would preclude us from maybe drilling the lateral length that we'd like to drill.

Gil Yang - BofA Merrill Lynch

You said you have 450 stages waiting on completion. What level is that? Is that level where you're comfortable with? Do you want to be higher, lower? And where would we see it go by the end of the year?

Dan Dinges

Well, we have a dedicated frac crew up there. That dedicated frac crew, we think, in maybe the winter would be frac-ing, say 60 or so stages a month. We would hope to get some better efficiencies in the better time period that would allow us to work off some of those wells that are currently waiting on completion, also those subject to, Gil, the take-away capacity and us completing the necessary pipelines to get to the Millennium and get back down to the Transco.

Gil Yang - BofA Merrill Lynch

Can you just give us an idea of what you're expecting in the Heath play for the wells, that's why you drilled?

Dan Dinges

It's a little early on that. We have again a well drilled. We've run pipe, it's a lateral well. We get a short lateral. We're not in the development mode right now. We're just trying to gather information. So the lateral length of the well we have, we would expect the oil rate to be less than what we would have as far as a development program going forward. But it is with an expiration date, Gil. It's a little bit early to be able to make that projection.

Operator

Your next question comes from the line of Robert Christensen.

Robert Christensen - Buckingham Research Group, Inc.

On the Eagle Ford shale, how are some of your early wells performing? Are they still in a -- are they declining in these later months here? Or are they hanging up there?

Dan Dinges

Don't know. We produced anywhere from 80 to 160 days on three of the wells. And those wells are still producing 360 to over 600 barrels. Excuse me, they're producing, yes, somewhere around that 350 to 600 barrels a day.

Robert Christensen - Buckingham Research Group, Inc.

And what would they have come on at?

Dan Dinges

They came on at about 575 barrels to a little over 1,000.

Robert Christensen - Buckingham Research Group, Inc.

A second question related to the Eagle Ford, if I may. What kind of EURs are you prepared to start your life out with the...

Dan Dinges

We have a range and a truck can drive through it, Robert. But it's 350 to 500 barrels. But again, we've only have a year of production yet.

Robert Christensen - Buckingham Research Group, Inc.

And if I may on the Montana well, have there been any other producers that have drilled somewhere nearby? Something similar that we could -- or are you the only guy within the...

Dan Dinges

No, we're not the only folks in the neighborhood. There are a couple of operators that I think are, well they are out there drilling. And again I don't have any data on their wells. But there is some activity in the Heath out in our area.

Operator

Your next question comes from the line of Biju Perincheril.

Biju Perincheril - Jefferies & Company, Inc.

I don't know if you mentioned this earlier. But how many Haynesville wells you think you will get total with the carry this year?

Dan Dinges

Let me see. I think we will get pushing a little over 20, probably 23 wells, something like that maybe.

Biju Perincheril - Jefferies & Company, Inc.

And your working interest would be roughly?

Dan Dinges

Well, it's going to be hard to say in those wells, Biju, because we have various levels. I haven't netted it down like that. We have various levels of working interest in each of those units. So that'd be hard to narrow it down like that.

Biju Perincheril - Jefferies & Company, Inc.

And then going back to the infrastructure in the Marcellus, is the Lenoxville's compressor station, is that still expected to come on this year and how many compressors? And can you give us some idea of capacity that would add?

Jeffrey Hutton

Lenoxville, the areas to the east of our core area. It'll have total capacity of again, capacity moves around a little bit. But it's targeted for about 250,000 a day. That compressor station will discharge in the Tennessee Gas Pipeline. And I can't give you a concrete answer on the timing. The site's been purchased. Their dry way currently being purchased. And it's just a little too early to get them service date for that station.

Operator

Your next question comes from the line of Seth Manoff [ph].

Unidentified Analyst

One question that I had is just to get clarification around your acreage position. If you had to put a percentage of the acreage position you have in Susquehanna, how much of that is perspective to longer laterals? And how much of that is perspective to only short lateral lengths because they're leased lines?

Dan Dinges

The majority of it is going to be available for the mid-range to longer range laterals.

Unidentified Analyst

So in majority being 80% roughly?

Dan Dinges

That's as good a number as I could throw out.

Unidentified Analyst

And then the longer laterals, what you're saying is generating 10 Bcf. Is that about right?

Dan Dinges

Well, we have a number of wells. And that count is growing with the number of wells that we have booked north of 10 Bcf.

Unidentified Analyst

And then so of the 10% and the 20% that's perspective to shorter laterals, that's what you guys are booking at 6.5?

Dan Dinges

In our release, we've mentioned that we kind of just -- because we weren't, and again intentionally conservative, but because we were, there was a delta between what we're seeing on the producing PDP wells and the PUDs, we felt like we needed to put a reason out there for the PUD booking at 6.5. And the reason is that we assumed a shorter lateral than we are averaging out there right now.

Unidentified Analyst

Just to be clear on the AFEs, the AFEs on the longer laterals are $5.5 million, is that right?

Dan Dinges

If we go with more stages of completion, it's going to be probably $6 million to $6.5 million.

Unidentified Analyst

And then how about the shorter laterals?

Dan Dinges

Shorter laterals will be around the $5 million.

Operator

Your next question comes from the line of Joe Magner.

Joseph Magner - Macquarie Research

Just a few questions on capital. Was there any explanation for the 2010 capital that came in higher than what you've guided to back in October? I think it total is around $850 million, and the latest guidance estimate was around $790 million.

Scott Schroeder

Joe, this is Scott. Our guidance was at $790 million from a -- Dan made a comment in the speech that from a finding cost perspective, the capital was in the $823 million, $828 million range. So we're about $30 million over that $790 million. What went through cash flow also picks up the infrastructure investment that we subsequently sold. And so that's why we felt it was a better illustration of what the capital program was at that $828 million, $830 million level. Again, it was just the longer laterals, the more completions, the lease act dollars. It was all the stuff that we illustrated in our investor presentations post the October call.

Joseph Magner - Macquarie Research

And then in addition to the or other than the midstream expenditures in 2010, are there any other items that -- any other big items that won't be repeated? I imagine there's Haynesville spending that's not going to be repeated next year due to the carriers. Can you quantify what those items might be?

Scott Schroeder

Well, you're right on in terms of the Haynesville spending. That ended up being about $45 million that was related to the Haynesville those non-op wells that we had planned on not participating in. So that is clearly the biggest ticket item that will go away. The other difference is when we've talked around the well costs in Marcellus a lot this morning. When we did the 2009 budget originally, that number was in the $3 million to $4 million range. And clearly the science and what we found and clearly the results show that what we did with longer laterals closer in spacing pays huge dividends from an economics and reserves perspective. That's all been captured in the $350 million program for the North. So the overages that you see will have already been captured in the $350 million. And both our regional managers are substituting and adjusting consistently to stay close to those levels, to stay right at their $350 million and $250 million respective capital levels.

Joseph Magner - Macquarie Research

Can you give us an update on current rig count in the North and the South? What the average might be for the full year and then the expected well counts for your various plays?

Dan Dinges

Total we're going to drill between 70 and 80 net wells for the company. In the South region, we have one rig running, and that is going to be in the Eagle Ford. We plan on drilling 20 net wells in the Eagle Ford in 2011. And we have five rigs running currently in the North region. And we plan on right now about 50 horizontal wells up there. Towards the end, we might farm out a couple of that's for rigs up around in the area in the north and with our drilling efficiencies and staying to our capital commitment, we might farm out a couple of those rigs for a brief period of time in the North.

Operator

Your next question comes from the line of Jack Aydin.

Jack Aydin - KeyBanc Capital Markets Inc.

With the 10 Bs bookings for the 50 whatever wells and the 6.5 B before the PUDs, do you see -- did you evaluate the lease or upside potential versus what you had before? Because you were using 5.5 Bs before, so did you guys do any analysis of that at all?

Dan Dinges

Well, we have not completed that study. We're still adding zeros to it. But we will work on that. And it is going to be an increase, Jack, as you might guess from where we were. The other thing that we're going to be looking at and evaluating a little bit in the year is also the upper Marcellus and the Purcell.

Our Purcell well out there has continued to produce extremely well. And we're trying to get our hands around and figure out how we're going to get a little bit more timely data, so we can quantify. Really the question you're asking also, Jack, what that adds to just the lower Marcellus, which is where all of our wells are currently completed.

Jack Aydin - KeyBanc Capital Markets Inc.

How much of your acreage lends itself to the Purcell formation?

Dan Dinges

Virtually all of it.

Jack Aydin - KeyBanc Capital Markets Inc.

One question for Jeff, what is the take-away do you have commitment on Tennessee line?

Jeffrey Hutton

Jack, it comes in stages. We're currently at the 150,000 a day level on Tennessee alone. And then that moves up to next year to 250,000 a day a take-away on Tennessee alone. And of course that's not inclusive of the take-away going to Transco and Millennium.

Operator

There are no further questions at this time.

Dan Dinges

Thank you, Beverly. I have no further comments, but Mr. Schroeder has a couple of closing comments.

Scott Schroeder

Thank you everybody for participating in the call. When we sat back and looked at just all the metrics that we reported in these three press releases, we thought we would have a little fun and take it from and just highlight those metrics in the form of the good news in David Letterman fashion. So the Top 10 Highlights of the Cabot Reports that were reported last night include three the potential joint ventures in the Haynesville, four new compressors for a total of seven at Lathrop, $5-plus natural gas hedges covering 2011 and 2012, 36% hedge for 2011, 36% PUD percentage held constant, 31% reserve growth, $1.05 per Mcfe all-in finding cost, 27% production growth, 10 Bcf realizations for 2010 Marcellus horizontal wells. And the number one highlight is maintained the $600 million capital program for the year.

Thank you for participating, and thank you for being supportive of Cabot.

Dan Dinges

Thank you.

Operator

Thank you for joining today's conference call. You may now disconnect.

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