Ladies and gentlemen, thank you for standing by, and welcome to the Cabot Oil and Gas 4th Quarter 2010 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. Thank you. I would now like to turn the conference over to Dan Dingus, Chairman, President and CEO.
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 Reed, our VP and Regional Manager of the South and our newly elected VP of Engineering and Technology, Steve Lindeman. I want to state that the forward looking statements release do apply to my comments today. At this time, we have several things to cover and expand on from the 3 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 I'll 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 $100,000,000 and with cash flow from operations of 4 $85,000,000 The company maintained our strong financial structure raising over $200,000,000 asset sales in the 4th 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 items, which include gain on sale, impairments, stock compensation and a true up excuse me, deferred taxes that net out. 4th quarter clean earnings were $20,000,000 on the strength of record production levels. While I do not normalize cash flow both the quarter and the year were impacted by the cash taxes associated with the gains from the 4th quarter asset sales.
This had approximately a 25 $1,000,000 to $30,000,000 lowering effect on reported cash flow. However, I'd gladly take the $211,000,000 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 is equally noteworthy that we held our PUD level at 36%, the same percentage reported at the end of 2,009.
This booking translates into a proved developed reserve increase of 30%. The value from this program has created for Cabot shareholders is illustrated by the fact with only 13% increase in year end SEC gas prices, Cabot realized a 100% increase in its SEC PV-ten to $3,200,000,000 That is a good demonstration of revision adjustments for the year. This compares to 4.63 Bcfe added last year. With all of the 20 10 increase 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 $100,000,000 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 5 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 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 HUDs 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 6 20 total 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 $828,000,000 which included 131,000,000 dollars 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 percent 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 slowdown related to the Lathrop compressor station Phase 2 permitting approval process.
I'll 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 release and the dynamics of our 2010 program. However, today there are there is over 1 100 excuse me 1.2 Bcf per day flowing into the Tennessee 300 line from ourselves and our peers in the 3 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 Q4 with 3 new construction and projects scheduled for completion. These projects include a 33 mile high pressure 24 inches pipeline from our Lathrop station to Transco Interstate Pipeline, a 35 mile 16 inches pressure 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.
Okay. Our operations plans for 20 11 have remained unchanged from our original budget. We are holding firm to our $600,000,000 capital program that has $350,000,000 directed towards the North region for the Mar take advantage take advantage of a short window of opportunity for natural gas price strength during the Q1 and hedged approximately 150,000,000 cubic foot production, which was hedged at a mark north of dollars and that is for all of the remainder of 20 11 and all of 20 12. This effort combined with the previous position has us 36% hedged in 2011 based on the midpoint equivalent guidance. We also have a good jump north of $5 for 20.12.
In the North region, our Marcellus area, as you saw in the press releases, continues to excel, achieving a new production record of 265,000,000 cubic foot gross per day predominantly from 51 horizontal wells with production growth at impressive rate of 36% over our 3rd quarter of 2010. Cabot continues to have great success as demonstrated by one of our recent completions that had an IP of over 100 foot lateral. Other recent 30 day averages include a 14,000,000 per day and 10,000,000 per day from several shorter lateral wells. We also just finished drilling a 6,100 plus use bilateral, which is another record for us. We plan to complete this well with a 26 stage frac.
In addition, we recently had a well achieved 3 Bcf cume production in just 8 months from a 15 stage completion, which is also a record on the cume production number in that shorter period of time. The well is currently still producing 9,000,000 a day. These statistics highlight the prolific nature of the 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 Bcf EUR for our PUDs in the area, which assumes a well with expected to produce 10 Bcf plus and we will get and as we get more data, we will continue to assess our reserve bookings. Cabot is currently running 5 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 4 compressors at the station, which will give us the station which will give the station a total of 7 compressors. With the start up of the 4th compressor, which we're currently commissioning, the capacity of Lathrop will be at 250,000,000 cubic foot per day. When units cubic foot per day. Again, actual flowing ability will be tied to the interstate takeaway capacity and the completion of the Williams Springville line from Lathrop to Transco, which is expected to be operational in the Q3.
In the Rocky Mountains area of the North region, Kevitt has drilled encased a Montana horizontal logcat located in the Heath play. We expect to complete this well in the Q2 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 $250,000,000 to the Eagle Ford. The company has successfully completed its 4th Eagle Ford well.
It's 100% well located in LaSalle 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 7.89 barrels of oil equivalent a day. This well is located in our Buckhorn area. The 5th company operated well, also a 100% Cabot is located in Fria County also in the Buckhorn area was drilled with a lateral of over 6,700 feet and is presently being completed. 2 additional wells have been drilled encased in the Buckhorn area and will be completed in late February March.
Additionally, our 18,000 acre area mutual interest with EOG Resources, the first well has been drilled encased. This well was drilled with over a drill or participate in 20 net Eagle Ford oil wells in 2011 also to ensure time and 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 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 non operated excuse me non producing with net production to Cabot of approximately 4 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.
Industry has discovered in the Marcellus and we will deliver significant returns with I think stellar reserve and production growth. Also we will allocate $250,000,000 in the oil window of the Eagle Ford, which will increase our oil reserves and will increase our oil production between 30% 70% year over year. So in CABIC, you have the best rate of return gas project in North America, which I think includes a rate of return comparison to many oil projects and the remainder of our capital is allocated to to see if there's any questions.
Your first question comes from the line of Brian Lively.
Good morning, Dan. How are you doing? Hi, Brian. Good. Just on the 6.5 Bcf PUD booking 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?
No, not a problem at all with depletion, not concerned that we'd be drilling with future PUDs till we recognize the exact size of each we average 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 we with that in the database we have, we recognize the 6.5 Bcf Budd booking.
That's helpful. But even if you take the smaller laterals and your average is 6.5Bs, what would you guys estimate as the 2P reserves per well for that lateral well?
Probably be a little bit north of there.
And then like what degree of production data would you need to see from your program, I guess, in 2011 to increase those the guidance EURs per well and that be reflected in both CapEx and volume estimates?
I think we'll have with these longer laterals and our longer laterals and increased number of stages per well, Once we get a year say production data behind us, we see the curve fit by that production. I think we'll at that point in time, Brian, we'll be comfortable maybe making a little bit more robust recognition of what we're hopeful to see.
Okay. And then last question for me. I noticed that the gas volumes are flattish in the second half of twenty eleven, understandably for infrastructure type uncertainties. But just wondering why liquids also appear to be flattish during the second half of twenty eleven?
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 emphasized, it's kind of 30% to 70% growth on those liquid volumes. And so we've taken a conservative stance based on the timing of the completions.
The other thing we've had challenge us in the last, say, 3 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.
Brian, I might add also in the South region, not unlike what we're seeing in the North region, there's a lot of infrastructure that needs to be in place out there also. And from a number of trucks hauling oil right now and the timing of getting some of that takeaway infrastructure capacity in place, we were a little bit conservative on that year end guidance on liquids.
Great. Thanks for the added color. Appreciate it.
Your next question comes from the line of Brian Singer.
Thanks. Good morning.
Hey, Brian.
Just following up on the last one. Can you give us your latest thoughts on the timing of Lazer, 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?
Yes. I'll let capacity when those pipelines do come on?
Yes. I'll let Jeff Putten is here and Jeff has been intimately involved with the negotiations and the transfer and transition to Williams. And I'll let Helmut update us on that.
Okay, Brian. The Springville pipeline with
it's going to connect Lakebrook
with Transco, It's under construction. Their timing, I don't know if you follow their 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, one to Millennium. That pipeline is also under construction, which means they have their permits and they have their The The stagecoach lateral is a little different animal because you have the interstate Tennessee line that Cabot already holds capacity on.
It connects the Stagecoach lateral. That's 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.
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 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 will by all means reflect that. Great, thank you. And then also on the Marcellus then
over what percent of your acreage in
Susquehanna you've drilled, the then over what percent of your acreage in Susquehanna you've drilled that's confirmed that spacing?
Well, we think the well spacing right now would be 1,000 feet and we've 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 spacing.
Great. Thanks.
And just I guess lastly on the acre spacing.
Great. Thanks. And just I guess lastly on the Heath well, I guess 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.
Your next question comes from the line of Michael Hall.
Congrats on the solid update. 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? Are you pretty tight and consistent across the different areas you drilled during the year? Or is there a meaningful amount of variation? And then then how much of your total acreage would you expect that in theory could be extrapolated to?
Well, from the area that we drilled, we did not see just a specific we did not see just a specific point in our in the area we've been drilling that recognize that we recognized 10 Bcf. We have seen some very, very strong wells within the parameter Bcf well down to the south of our acreage. The 3 wells that we mentioned in the press release that have cumed almost 6 Bcf and are still producing 34,000,000 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're seeing these wells, certainly the added lateral lengths and stages have an impact on it. And from the our ability to evaluate our 3 d 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 3 d.
Okay. And so if I'm thinking about you'd say on the 6.5 Bcf PUD booking at 10 stages, it's about $650,000,000 a stage. Is that pretty consistent then with PDP as well? And it really is just the length of lateral number of stages? Or like how has that number been risked, if you will?
Yes. We have seen some consistencies. It's a I don't want to get into a myopically looking at each stage. But from an average overall average standpoint and looking now at the 500 and 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.
Sure. Okay. And then what are well costs trending like in the Marcellus as well as the Eagle Ford at this point?
Well, it is the wells are being drilled stages. So the number of stages like a well that we've recognized here on our PUD bookings would be a $5,000,000 to $5,500,000
well. Then what about in the Eagle Ford with like a 6,000 foot lateral?
6,000 foot lateral, we're seeing probably 6 0.5 to 7.5.
Okay. 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?
Yes. I'm sorry. I didn't get the name.
It's Amir from Stifel. Hello, Amir. A quick question on as you move from 11% to 12%, can you just talk about the takeaway whether it's the Tennessee or the laser line? Just do you have takeaway capacity sort of firmed up for 12?
I'll turn that over to Jeff also and he can kind of run through not only maybe the that capacity, also some of the things we've done on our marketing efforts.
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 in excess of 15, 20 year kind of arrangements and also include the right for Cabot to extend those to even longer periods of time. So there's no fear in losing your capacities once these pipelines are constructed. Those are 2 steps that we've taken to ensure takeaway. There's also another aspect of this and that's the long term takeaway agreement that we have on Tennessee Gas Pipeline because those agreements allow for I think the early one expires in 5 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're in great shape. The gas that we're going to continue to produce and deliver to Tennessee, we feel like we're in great shape for a long, long time.
Sounds good. 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 4th well was? Was that in the Frio County?
The 4th well is in LaSalle County.
LaSalle County, okay.
Yes, which is by the way our bicorn area covers kind of what they call 4 county area right there. So it's all kind of part of our corn prospect.
And most of your 11 remaining 11 EOPRA wells will all be in that area?
The operated wells will be in that area and the non operated wells with the EOG Resources will west of there in our AMI area.
Perfect. Thank you very much guys.
Your next question comes from the line of Ray Deacon.
Yes. Hey, Dan, I was wondering if you could elaborate a little bit more on the previous question about the 10 Bcf EURs. Is that I guess how large how many acres of the 160,000 do you think that is going to be applicable to, I guess? Or how much have you kind of derisked so far? Well,
we have recently drilled a well all the way say 8 miles to the outside of our area. And that not been completed yet, but it is every bit looks every bit as 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 aware of that we feel comfortable with our majority of our acreage position put it that way. There's certainly going to be acreage Ray that is gets to the periphery that we have not yet evaluated by drilling.
Okay. Got it. Great. And I guess I've seen some permitting activity in the Marmaden and 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?
Is that in Oklahoma?
Yes, exactly. Right, right. Yes. I guess Beaver County and then to the south in Texas also.
We have you're aware that we have a lot of acreage in Oklahoma in the Mid Continent area. There's a number of plays that are being looked at up there for horizontal oil drilling and we're evaluating some of those plays and the Marminton is one of those plays that we're currently evaluating.
Okay. Got it. Do you see any drilling activity this year or mainly just permitting?
No, I think we will drill.
Okay, got it. And I guess just to be clear on the takeaway side and in terms of compression, can you just summarize, It seems like there is more you have more compression capacity than what you were talking about last quarter. Is that a fair
comment?
Yes. Jeff? Sure.
Compression is not an exact science. In other words, the capacity on compression can be altered or modified based on 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 more throughput out of the same horsepower. So it does move around a little bit, but I think one line that sticks out in the speech today is the laser compressor station can run be modified to operate at around 450,000,000 a day of throughput when all of the other options, the de highs and the slug catchers and everything is modified, then we'll be in good shape come 3 months or so for that station to operate fully. Is that helpful?
Your next question comes from the line of Gil Yang.
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?
Well, the PDP is for our 20 10 program was 2019 program was various. We had anywhere from 9 to 19 stages in the bookings that averaged out at 10 Bcf.
Is there an average number of stages or don't have that?
Well, yes, it's between say 1215.
Okay. What in your lateral length decisions, what's driving the length that you're deciding to drill those wells?
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've blocked up in Susquehanna and certainly Cabot has the largest position in Susquehanna. We're trying to affect 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 outline 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 where the dollars that our group spends is allocated 100% to Cabot and the dollars they spend would be allocated 100% to their position. And it also holds true with the equity gas that we're moving out of the field. Again, we're not able to move 100 percent 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 3rd 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 and infrastructure and capacity for Cabot Equity Gas. We've invested over $1,000,000,000 in this county Susquehanna County right now and we are working that return. I think we 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 that regard. Long winded answer to illustrate to you that and 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 a the
a on completion. What level is that? Is that a level you're comfortable with? Do you want it to be higher, lower? And where would see it go by the end
of the year? We have a dedicated frac crew up there. That dedicated frac crew, we think and maybe the winner would be fracking 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 takeaway capacity and us completing the necessary pipelines to get to the Millennium and get back get down to Transco.
Well, the test well that's actually drilled?
It's a little early on that. We have a again a well drilled. We've run pipe. It's a lateral well. We did a short lateral.
We're not in the development mode right now. We're just trying to gather information. Rate to be less than what we would have as far as a development program going forward. But it is with an exploration play, Gillette. It's a little bit early to be able to make that projection.
Okay. All right. Thanks a lot.
Thank you.
Your next question comes from the line of Jack Aydin.
Hey guys, all my questions are answered. Thanks a lot.
All right. Thank you, guys. Appreciate it.
Your next question comes from the line of Dan Dan 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 in a are they declining in these later months here or are they hanging up there?
Well, no, we have we produced anywhere 80 to 160 days on 3 of the wells and those wells are still producing 360 to over 600 barrels excuse me, they're producing somewhere around that, 350 to 600 barrels a day.
And what would they have come on
at? They came on at
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 with
this? Yes. We have a range and truck can drive through it, Robert, but it's 3.50 to 500 barrels. Okay. But again, we don't have a year of production yet.
Yes, that's I'm assuming it's conservative. And if I may, on the Montana well, have there been any other producers, 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?
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 heat out in our area.
Well, 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
Haynesville wells are you think you
will get drilled with the carry this year?
Let me see. I think we will get pushing a little over 2020 probably 2023 well something like that maybe.
And your working interest would be roughly?
Well, it's going to be hard to say in those wells Biju because we have various levels of 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.
Okay. That's fine. And then going back to the infrastructure in the Marcellus, is the Lenox Hill compressor
Can you give us some idea of the capacity that would
add? Yes.
Okay. Lennoxville is the area to the east of our core area. It will have total capacity of again, capacity moves around a little bit, but it's targeted for about 250 1,000 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. They're dry away currently being purchased. And it's just a little too early to give an in service date for that station.
Okay. That's fair. Thanks.
That's all I had. Thank you.
Thanks, Vijay.
Your next question comes from the line of Seth Manoff.
Hi there. Can you hear me?
Yes. Great. Sorry. Congratulations on the quarter. One question that I had is just 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 prospective to longer laterals and how much of that is prospective to only short lateral lengths because they are lease lines?
The majority of it is going to be available for the mid range to longer range laterals.
Okay. So a majority then the longer laterals what you're saying is generating 10 Bcf is that about right?
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.
Okay. And then so of the and then the 20% that's perspective to shorter laterals,
percent? Yes. And in our release, we had mentioned that we kind of just because we were and again intentionally conservative, but because we were and 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.
Okay. And then just to be clear on AFEs, the AFEs on the longer laterals are $5,500,000 is that right?
No, but if we go with more stages of completion, it's going to be probably $6,000,000 to $6,500,000 $6,000,000 to $6,500,000 And then
how about the shorter laterals?
Well, the shorter laterals will be around the $5,000,000
$5,000,000 Okay, great. All right. Thank you very much for your time.
Thank you, Sam.
All right.
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 guided to back in October? I think the total is around 850 and the latest guidance estimate was around 7.90 dollars
Joe, this is Scott. We our guidance was at $790,000,000 from a Dan made a comment in the speech that our from a finding cost perspective, the capital was in the $8.23,000,000 $8.28 range. So we're about $30,000,000 over that $790,000,000 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 $820,000,000 to $830,000,000 level. Again, it was just laterals, the more completions, the lease act dollars, it was all the stuff that we illustrated in our investor presentations post the October call.
Okay. And then in addition to the or other than the midstream expenditures for 20 10, are there any other items that any of the other big items that carries. Can you quantify what those items might be?
Well, you're right on in terms of the that ended up being about $45,000,000 that was in the 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 we've talked around the well cost in Marcellus a lot this morning. When we did the 2,009 budget originally, that number was in the $3,000,000 to $4,000,000 range and clearly the science and what we found and clearly the results show that what did with longer laterals closer in spacing paid huge dividends from an economics and directive. That's all been captured in the $350,000,000 program for the North.
So the overages that you see will have already been captured in the $350,000,000 and both our regional managers are substituting and adjusting consistently to stay close to those levels. Okay. To stay right at their $350,000,000 and their $250,000,000 respective capital levels.
Okay. And 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 expected well counts for your
various plays?
Well, in total, we're going to drill between 70 80 net wells for the company. In the South region, we have 1 rig running and that is going to be in the Eagle Ford.
We plan on drilling 20
net wells in the Eagle Ford. 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 have asked for rigs up around in the area 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.
Okay. That's all I have. Thanks.
Thanks, Joe.
Your next
10Bs booking for those 50 whatever wells and the 6.5 B for the pads, Do you did you evaluate the resource 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?
Well, we have not completed that study. We're still adding zeros to it. So 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 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 takeaway? Do you have commitment on Tennessee Line?
Okay, Jack. It comes in stages. We're currently at the 150,000 a day level on Tennessee alone. And then we that moves up to next year to 250,000 a day of takeaway on Tennessee alone. And of course, that's not inclusive of the takeaway going to Transco and Millennium.
Thank you. Thanks, Jack.
There are no further questions at this time.
Okay. Thank you, Beverly. I will I have no further comments, but Mr. Schroeder has a couple of closing comments. Thank you everybody for participating in
the call. When we sat back and looked at just all the metrics that we've 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 from a in David Letterman fashion. So the top ten highlights of the Cabot reports that were reported last night include 3 potential joint ventures in the Haynesville, 4 new compressors for a total of 7 at Lathrop, dollars 5 plus natural gas hedges covering 2011 2012, 36% hedged for 2011, 36 percent PUD percentage held constant, 31% reserve growth, dollars 1.5 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 $600,000,000 capital program for the year. Thank you for participating and thank you for being supportive of Cabot.