Coterra Energy Inc (CTRA) 2010 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the Cabot Oil & Gas fourth quarter 2010 and year-end 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 conference over to Dan Dinges, Chairman, President and Chief Executive Officer.

Thank you, Beverly. 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, Regional Manager of the South; and our newly elected to VP of Engineering and Technology, Steve Lindemann.

I want to state that the boiler plate 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. We'll briefly cover the year-end financial results, the year-end reserve metrics, and then on a more detailed discussion of our operations including the plans for 2011. I will be brief and allow time for Q and 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 a 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, impairment, 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. While I do not normalize cash flow, both the quarter and the quarter 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 would gladly take the $211 million pre-tax 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's 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 the program had created for Cabot shareholders as illustrated by the fact with 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 a $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 in 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 looked at our PUD profile as a balancing act with future capital needs, finding cost metrics over the long term, and realistic assessment of how much PUD drilling is prudent to execute in our program over the next several years.

n light of the current natural gas trip, 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 of these PUDs can be drilled easily with anticipated cash flow. Even with this reclassification of P2 from PUD, the performance provisions 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 releases -- excuse me, 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 was -- growth was 26.8% increase. This record-setting performance was achieved even after the restriction -- restricted rates due to the slow down related to the Lathrop Compressor Station phase 2 permitting approval process. I will have additional comments on our phase 2 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. Some may feel this guidance is conservative based on our reserve lease and the dynamics of the 2010 program. However, today, there are over -- there is over -- excuse me, 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, that's a strategy we implemented over a year ago, we are going to be comfortable with the 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 Pressured pipeline that will connect our Northern acreage position with Millennium Interstate Pipeline and the expansion of the Stagecoach Lateral designed to move gas out of our core area also to the Millennium line.

Our operations plans for 2011 have remained unchanged from our original budget. We are 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 and impressive rate of 36% over the 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 30-day average of approximately 19 million cubic foot per day from a 3700-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 3 BCF cume production in eight months from a 15 stage completion, which is also a record on the production number in that short a period of time. The well is currently still producing 9 million a day. These statistics highlight the prolific nature of this area of the 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 Bcfe UR 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 the 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, that received all the required permits to run an additional four compressors at the station, which will give us the station -- which will give the station a total of seven compressors. With the startup of the fourth compressor, which we are currently commissioning, the capacity at 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 at 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 Williams Springville line from Lathrop to Transco, which is expected to be operational in the third quarter.

In the Rocky Mountains area of the North region, Cabot has drilled and cased a Montana horizontal wild cat located in the Heath play. We expect to complete the 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 are going to allocate all of our $250 million to the Eagle Ford, the Company has successfully completed its fourth Eagle Ford well. It's 100% well located in La Salle County and 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, encased 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 flow back 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 its Haynesville 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 are 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 non-operated -- excuse me non-producing, 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 will spend $350 million in the best area industry as 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 the oil reserves and will increase our oil production between 30% and 70% year over year. In Cabot, you have the best rate of return, gas project in North America, which I think includes a rate of return in comparison to many oil projects, and the remainder of our capital is allocated to a good rate of return project in the Eagle Ford. Beverly, with those comments, I will now turn it back to you to see if there is any questions.

(Operator Instructions).Your first question comes from the line of Brian Lively.

Good morning, Dan. How are you doing?

Hey, Brian. Good.

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

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

That is helpful. Even if you take the smaller lateral, and your average is 6.5 b, what would you estimate as the 2 P reserves per well for that lateral well?

Probably a little North of there.

What degree of production data would you need to see from your program in 2011 to increase those guiding EURs (inaudible) per well and would that be reflected in the CapEx and volume estimates?

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

Okay. Last question for me, I notice that the gap volumes are flattish in the second half of 2011, understandably for infrastructure type uncertainties. But wondering why liquids also appear to be flattish during the second half of 2011.

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

Brian, I might add also, in the South region, not unlike what we are 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.

Great, thanks for the added color. I appreciate it.

Your next question comes from the line of Brian Singer.

Thanks. Good morning.

Hello, Brian.

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

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

Okay, Brian. The spring built pipeline that will connect Lathrop with Transco, it's under construction. Their timing -- I don't know if you followed their call last week, their timing is still July, maybe the end of July. So, we are not far from agreeing with that. But, again, they are under construction. With Laser, that is another pipeline going to Millennium. That pipeline is also under construction, which means they have their permits and have crews out there.

We anticipate them to be approximately the same schedule as Williams. The Stagecoach lateral is a little different animals because you have the interstate Tennessee line that Cabot already holds capacity on that connects the Stagecoach lateral. That is anticipated to be 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.

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 in the guidance we currently have. As we get closer and we can make the determination that the startups will occur maybe sooner than our guidance, then certainly we will, by all means, reflect that.

Great, thank you. On the Marcellus, can you refresh us on your well spacing assumptions, and then over what percent of your acreage in Susquehanna you have drilled that's confirmed?

We think the well spacing right now would be a 1,000 feet. We have drilled some thousand feet off sets, 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.

Great, thank you.

And the spacing, we think, would be -- at that, would be about 80-acre spacing.

Great. Thanks. Lastly, on the Heath well, any comments so far ahead of completion, any reason to be optimistic or pessimistic?

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

Great, thank you.

Your next question comes from the line of Michael Hall.

Thanks, good morning.

Michael.

Congrats on the solid update. Curious on the 10 Bcf wells for 2010, you had a couple of focus areas in the 2010 program. What was the variation around that10 Bcf?Are you tight and consistent across the different areas that you drilled during the year? Is there a meaningful amount of variation, and how much of your total acreage would you expect that could be extrapolated too?

From the area that we have drilled, we did not see just a specific point in our -- in the area we have been drilling that recognized -- that we recognize 10 Bcf. We have seen some very, very strong wells within the parameter of the areas that we have drilled. We have seen extremely strong well down, say a 10 Bcf or 12 Bcf well, down to the south of the acreage. The three wells that we mentioned in the press release that have cumed almost 6 Bcf and are still producing 34 million cubic foot a day. That was 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 are seeing these wells, certainly the added lateral lengths and stages have an impact on it. And from our ability to evaluate our 3-D that we have out there right now, we are still early in the game, but we are seeing what kind of effect well placement has by the use of 3-D.

Okay. On the 6.5 Bcf PUD booking, ten stages, it's $650 million a stage, is that pretty consistent then with the PDP as well? It really is just the length of lateral number of stages, or how is that number been risked, if you will?

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

Okay. What are well costs trending like in the Marcellus as well as the Eagle Ford at this point.

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

What about in the Eagle Ford with a 6,000-foot lateral?

6,000-foot lateral, we are seeing probably $6.5 million to $7.5 million.

Okay. Great, thanks very much.

Your next question comes from the line of Amir Arif. Your line is open.

Hello. Thanks, good morning. Can you hear me now.

I'm sorry I didn't get the name.

It's Amir, from Stifel. Quick question on, as you move from 2011 to 2012.Can you talk about the take away, whether it's the Tennessee or the Laser line. Do you have take away capacity firmed up for 2012?

I will turn that over to Jeff also, and he can run through not only maybe the capacity, but also some of the things that we have done on our marketing efforts.

Yes. The way this is laid out for us, the capacity on these pipelines that are being constructed on behalf, such as the Williams Line and the Laser Pipeline, those are long-term -- when I say long term, in excess of 15 year, 20 year arrangements, and also include the right for Cabot to extend those to even longer periods of time. So, there is no fear in losing your capacities once these pipelines are constructed. Those are two steps that we have taken to ensure take away.

There is another aspect of this, and that is the long-term take away agreements 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 leaving the area to Millennium and TransCo, we feel like we are in great shape. For gas that we are going to continue to produce and deliver to Tennessee, we feel like we are in great shape for a long, long time.

Sounds good. Just a quick question on the Eagle Ford. I apologize if you answered this. I hopped on late. Can you tell us where the fourth well is? Was that in the Frio County?

The fourth well was in La Salle County. Which is, by the way, our Buckhorn area covers a four-county area right there. So it's all part of our Buckhorn prospect.

Most of your 11 -- remaining 11 Eagle Ford wells will be in that area?

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

Perfect. Thank you very much, guys.

Your next question comes from the line of Ray Deacon.

Hello. Dan, I was wondering if you could elaborate a little bit more on the previous question about the 10 Bcf EURs. How many acres of the 160,000 do you think that will be applicable to, or how much have you de-risked so far?

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 is -- looks every bit as good, and in some cases -- well, looks every bit as good as the wells that we have completed. There is also wells to the north that we have seen or are at least aware of that we feel comfortable with our majority of our acreage position, put it that way. There certainly is going to be acreage, Ray, that gets to the periphery that we have not yet evaluated by drilling.

Got it. I had seen some permitting activity in the Marmiton, and I was wondering if could you talk about whether you are going to drill a well there or keeping an eye on it?

Is that in Oklahoma?

Yes, exactly right. I guess Beaver County and then to the south in Texas, also.

We have -- you are aware that we have a lot of acreage in Oklahoma in the mid-continent area. There is a number of plays that are being looked at up there for horizontal oil drilling. We are evaluating some of those plays, and Marmiton is one of those plays that we are currently evaluating.

Got it. Do you see any drilling activity this year or mainly just permitting and -- ?

No, I think we will drill.

Okay. Got it. To be clear, on the take away side, in terms of compression, can you summarize, it seems like there is more -- you have more compression capacity than what you were talking about last quarter. Is that fair, a fair comment?

Jeff?

Sure. Compression is not an exact science. In other words, the capacity on compression can be altered or modified based on the different operating parameters that you want to establish. So, in other words, to say it simply, if you want to run a higher suction pressure, you can get the same throughput out of the same horsepower .It does move around a little bit. One line that 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, (inaudible) the slow catchers and everything is modified, we will be in good shape come three months or so, for that station to operate fully. Is that helpful?

Yes. That's great. Thank you.

Your next question comes from the line of Gil Yang.

Good morning. I just wanted to clarify the PUD booking a little bit more. 6.6 Bcf for the PUDs, and PDPs were booked at 10. What are the number of stages for the PDPs versus the PUDs?

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

Is there an average number of stages, or you don't have that?

Yes. It's between say 12 and 15.

Okay. In your lateral length decisions, what is driving the length that you are deciding to drill those wells?

Well, Gil, we 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 are trying to effect trades of our acreage, swaps of our acreage that would allow companies that have a minority position, an acre here, an acre there within our outline area to -- us trade acreage with them and allow them to block up where their position is. And allow us to block up where our position is, where the dollars that our group spends is allocated 100% to Cabot. The dollars they spend would be allocated 100% to their position.

It also holds true with the equity gas that we are moving out of the field. Again, we are 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 invested over $1 billion in this county, Susquehanna County right now, and we are working that return. I think we have a spectacular return, but, nevertheless, we don't have room for all our gas. That's why the trades are being negotiated, have been executed, and we continue moving in that regard.

Long-winded answer to illustrate to you that also in some cases, those negotiations might affect the placement of wells. But also there are hold outs 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 would like to drill.

I appreciate the detailed answer. You said you have 450 stages waiting on completion. What level is that? Is that a level that you are comfortable with? Do you want it to be higher, lower and where would it go by the end of the year?

We have a dedicated frac crew up there. That dedicated frac crew, we think in maybe the winter, would be fracing 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 though subject to, Gil, the take away capacity and us completing the necessary pipelines to get to the Millennium and get back -- get down to TransCo.

Okay, great. The last question is, could you give us an idea of what you are expecting in the Heath play for the test wells you drilled?

It's a little early on that. We have again a well drilled. We have run pipe. It's a lateral well. We did a short lateral. We are not in the development mode right now. We are 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's -- it is with an expiration play, Gil, it's a little bit early to be able to make that projection.

Okay. Thanks a lot.

Thank you.

Your next question comes from the line of Jack Aydin.

Hello, guys, all my questions are answered. Thanks a lot.

All right. Thank you. Appreciate it.

Your next question comes from the line of Dan Morrison.

My questions have been answered as well. Thanks

Thanks, Dan.

Your next question comes from the line of Robert Christiansen.

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

Well, we have -- 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 are producing somewhere, yes around that, 350 to 600 barrels a day.

What would they have come on at?

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

A second question related to the Eagle Ford, if I may, what kind of EURs are you prepared to start your life out at with this point?

We have a range, and a truck can drive through it Robert, but it's 350 to 500 barrels.

Okay.

But, again, we only have a year of production yet.

Yes. That's assuming it's conservative. 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 -- ?

We are not the only folks in the neighborhood. There are a couple of operators that are out there drilling. Again, I don't have any data on their wells, but there is some activity in the Heath, out in our area.

Thank you very much, and congratulations.

Thanks, Robert.

Your next question comes from the line of Biju Perincheril.

Hi, Dan, a couple of quick questions. I don't know if you mentioned this earlier, but how many Hanesville wells do you think you will get total with the carry this year?

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

And your working interest would be roughly-- ?

Well, it will be hard to say in those wells 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 would be hard to narrow it down like that.

That's fine. And then going back to the infrastructure in the Marcellus, if the Lennox Hills Compressor Station. Is that still expected to come on this year, and how many compressors and can you give us an idea of the capacity that will add?

Jeff?

Okay. Lennoxville is the area to the east of our core area. It will have total capacity of, again, capacity is around a bit, but it is 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 has been purchased. There is right away currently being purchased, and it's just a little too early to give an in-service date for that station.

That's fair. Thanks, that's all I had.

Thanks, Biju.

Your next question comes from the line of Seth Manoff.

Hi there. Can you hear me?

Yes.

Congratulations on the quarter. One question I had was to get clarification around your acreage position. If you had to put a percentage on, 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 of your lease finds?

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

Okay. A majority being 80%, roughly?

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

Okay. Then the longer laterals, what you are saying is generating 10 Bcf, is that about right?

We have a number of wells, and that count is growing with the number of wells that we have booked north of 10 Bcf. Of the, the 20% that's perspective to shorter laterals, that is what you guys are booking at, 6.5 Bcf. Is that correct? In our release we mentioned that we -- because we weren't -- again, intentionally conservative, but because we were and there was a delta between what we are 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.

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

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

6 to 6.5. How about the shorter laterals?

The shorter laterals will be around the $5 million.

$5 million. Okay. Great. Thank you very much for your time.

Thank you, Seth.

Your next question comes from the line of Joe Magner.

Good morning. Thanks. Just a few questions on capital. Was there any explanation for the 2010 capital that came in higher than what you had got it to back in October? I think it totals around 850 in the latest guidance estimate was around 790.

Joe, this is Scott. Our guidance was at $790 million, from -- Dan made a comment in the speech that from a finding cost perspective the capital was in the $823 million, $828 million range. We are about $30 million over that $790 million. What went through cash flow also picks up the infrastructure investment that we subsequently sold. That is why we felt it was a better illustration of what the capital program was at that $820 million to $830 million level. Again, it was just the longer laterals, the more completions, the least act dollars. It was all the stuff that we illustrated in our investor presentations, post the October call.

In addition to -- other than the midstream expenditures, are there any other big items that won't be repeated? I imagine there is some Haynesville spending that is not going be repeated due to the carries. Can you quantify what those items might be?

You are 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. That is clearly the biggest ticket item that will go away. The other difference is, we talked around the well cost in Marcellus a lot this morning. When we did the 2009 budget originally, that number was in the $3 million to $4 million range.

Clearly the science in what we found, and the results show that what we did with longer laterals closer in spacing paid huge dividend from an economics and a reserves perspective. That has all been captured in the $350 million program for the North. The overage that you see will have been captured in the 350, and both our regional managers are substituting and adjusting consistently to stay close to those levels. To stay right at the 350 and 250 respective capital levels.

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

Well, total, we are 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. Toward the end we might farm out, a couple that asked for rigs around in the area of the North, and with our drilling efficiencies, our capital commitment, we might farm out a couple of those rigs for a brief period of time in the North.

Okay. That's all I have. Thanks.

Thanks, Joe.

Your next question comes from the line of Jack Aydin.

Hi, Dan.

Hello, Jack.

With the 10b's booking for the 50 (inaudible) wells and the 6.5 B for the PUD, did you evaluate the lease or sub-site potential versus what you had before because you were using 5.5 Bs before? Did you guys do any analysis of that at all?

Well, we have not completed that study. We are 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 are going to be looking at and evaluating a little bit in the year is the upper Marcellus and Purcell. The Purcell well out there has continued to produce extremely well, and we are trying to get our hands around and figure out how we are going to get a little bit more timely data, so that we can quantify really the question you are asking, also, Jack. What that adds to just the lower Marcellus, which is where all of our wells are currently completed.

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

Virtually all of it.

All of it? One question for Jeff, what is the take away that you have commitment on Tennessee line?

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

Thank you.

Thanks, Jack.

There are no further questions at this time.

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

Thank you, everybody for participating on the call. When we sat back and looked at just all the metrics that we have reported in these three press releases, we thought we would have a little fun and highlight those metrics in the form of the good news from -- in David Letterman fashion. The top ten highlights of the Cabot reports that were reported last night include three 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 per 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.

Thank you.

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