Coterra Energy Inc (CTRA) 2009 Q4 法說會逐字稿

Good morning. My name is Stephanie and I will be your conference operator today. At this time I would like to welcome everyone to the Cabot Oil & Gas fourth quarter and year-end 2009 conference call. All lines have been placed on mute to prevent any background noise. After speakers remark there is will be a question-and-answer session. (Operator Instructions). Thank you. I would now like to turn the conference over to Mr. Dan Dinges, Chairman, President, and CEO. Please go ahead, sir.

Thank you, Stephanie. Good morning. Thank you for joining us for our year-end teleconference call. I have Mike Walen with me, Scott Schroeder, Jeff Hutton and Chuck Smythe.

Before we start let me say the standard boiler plate forward-looking statements included on the Press Releases apply to my comments today. At this time, we do have many things to cover and expand on from three press releases that were issued last night. I will briefly cover the year-end financials, year-end reserve metrics, and then a more in depth discussion on the operations and our plans for 2010. We will make every effort to be brief to allow ample time for questions.

Cabot Oil & Gas reported strong financial results for the year with earnings just under $150 million and with cash flow exceeding $600 million, the Company was able to pursue its investment objectives and deliver growth while still maintaining a strong financial structure. From a [cleans] earning perspective, net income was $178 million. The selected items include a loss on sale, impairment, stock compensation and mark to market for 2012 basis hedges. Debt, decreased slightly from 2008 levels to $805 million and our capitalization ratio remains around 30%. The producing property impairment relates to two fields, one was in the Rockies and the other in south Texas. All in all really after a turbulent start of the year due to the world economic condition, these 2009 results fall into the top quartile for historic results.

Let's move through reserve metrics -- from a value-added perspective one of the key metrics to any organization's growth in our industry is the ability to stack up reserves at an economic investment level. Cabot once again was successful, growing reserves 6% year-over-year after fully complying with the new SEC reserve rules. Under the old methodology, reserve growth would have been 17%, the Company was able to add 463 Bcfe before production and revision adjustments for the year all from our organic effort. With all of the 2009 increases coming from our organic program, the corresponding drilling finding costs was $0.83 approximate per Mcfe. Let me get a bit more granular as it relates to reserves. Clearly there's significant noise in interpretation of the new rules. What Cabot did was remove all of our vintage PUDs that fell outside of the five year development window. In other words the PUDs put prior to 2005. The only exception is 16 Bcfe which was -- which are delayed by external factors. In terms of the expanded PUD definition that has been translated by industry into significant PUD bookings, we looked at it as a balancing act -- future capital needs, finding costs metrics over the long term, and a realistic assessment of how much PUD drilling we want in our future programs.

Cabot's new reserve benchmark is just under 2.1 Tcfe. The Company replaced 450% of its production at a finding cost of $1.28 per Mcfe. This finding cost includes a capital investment on leases, including Susquehanna County which will certainly pay dividends for years to come. Excluding these lease investments, the Company's finding costs fell below the $1 mark at a $0.97 per Mcfe. The Company still maintains a modest PUD booking level of only 36%. As a sensitivity, under the old methodology, Cabot would record reserves of just under 2.3 Tcfe or up 17% year-over-year. The new standard impacts the Company's year-end reserves in the revision category by reducing our reserves by 222 Bcfe which is partially offset by 22 Bcfe positive performance revision.

This revision reflects two requirements. First instead of using the December 31st [tinnery up] price of $5.79, under the new SEC rules, the Company must now utilize the average price from the first of each month which is $3.87 for 2009. This one-third drop in natural gas price reduces the Company's 2009 reserves by 102 Bcfe all being Teel reserves. Clearly, Cabot's reserve bookings at 98% natural gas adversely impacted year-end reserves more so than oil names that experienced a higher oil price under the new SEC rules. The second SEC change impacting this year's reserves is the enforcement of the [requirement] that proved undeveloped must be developed within five years from initial booking. Our enormous drilling success in PA and east Texas, the Company has allocated its capital program to primarily develop those assets requiring the deferral of previously booked PUDs out beyond the five year window. This change in development strategy requires the Company to reclassify 120 Bcfe reserves from the proved undeveloped category to the probable category. Fortunately for Cabot all of these related to areas where the acreage is held by production.

From our investment program during the year we added over 30,000 acres to our leasehold in Pennsylvania and east Texas. Both of these areas continue to see significant levels of activity of 70% of the 2010 program focused in Pennsylvania, and the remainder in east Texas. In terms of production, the Company reached a milestone with full year production number of 103 Bcfe or 8% increase over 2008. Last night, we posted guidance to our -- updates to our guidance for 2010, that held our production growth rate of 18% to 22%. In regards to our 2010 expense guidance, we did adjust for DD&A to take into account reserve changes and the additional lease amortization.

Let's move to operations. 2009 was an eventful year -- a pivotal year -- for Cabot, as the Company was almost purely a resource driven company. It was the first year where a vast majority of our investment was earmarked for repeatable low risk targets in east Texas and the Marcellus Shale in northeastern PA. Our total 2009 capital program was split 60/40 in each area, respectively.

Now let's move to the Marcellus. This area is the centerpiece for Cabot's future strategy. It is developing into a true Company maker and it is a world class resource. Early on we were conservative with our judgment regarding the potential of this play. Now it has met and exceeded all our expectations and we know it will be the driving force for Cabot for years to come. Cabot Oil & Gas Corporation has leased over 190,000 gross and net acres in the northeast PA play with most of that acreage focused in Susquehanna county. By and large, we have five year renewable leases with a 12.5% royalty.

Our strategy was from day one to focus on one area where we believe the geology supported an effort to concentrate our leasing, knowing that all Marcellus acreage is not created equally. Subsequently, we were able to mask essentially a single block of Marcellus acreage. We are confident this strategy will result in growing efficiencies and drilling completions, and pipelining as the play expands. During 2009, we drilled 30 horizontal wells and have 14 of those wells in line. We utilized up to six fit for purpose rigs to accomplish the program. Our well cost have stayed relatively constant between say $3.5 million and $3.8 million completed depending on the length of the laterals and number of stimulation stages. Since the first of 2009, our drilling best practices program has reduced the time to reach total depth on a horizontal well approximately 62%, to 21 days. More work needs be done to reduce further the costs. But we view this accomplishment as certainly a good start.

Now lets talk about the bottom line production and reserves. We were very pleased with the results of our wells so far. We ended 2009 producing about 72 million cubic foot of gas per day. However, delays due to weather and delays associated with a pipeline right away and stream crossing permit somewhat reduced our 2009 exit rates. We estimate that just weighing on the stream crossing permit delayed approximately 10 million cubic foot of gas per day from two wells. Anyway, with those issues resolved, we can report that our current gross production rate is greater than 100 million cubic foot of gas per day flowing through our Teel Station. The majority of that coming from just 19 horizontal wells. Also, at this time, we have 22 additional wells that are waiting to be cased and completed. 17 of these 22 are horizontal wells.

Obviously the Marcellus is an exceptional reservoir. Our 2009 program had an IP average of 7.5 million per day, and a 30 day average of 6.9 million cubic foot per day. The estimated ultimate recovery has increased from 4.5 Bcfe to north of 5.5 Bcfe per well. We have seen no diminishing results as we step out, and feel that our drilling and that of our peers has essentially derisked our entire acreage block. Is there room for enhancing our program? Certainly we think there is. We have achieved these results while completing laterals that average only 2800 feet so far with an average of eight stimulation stages.

As we lengthen our laterals -- and we recently finished one at 4500 feet -- and we increase our frac stages which we plan on getting up to about 15, we expect to realize continued improvement in rates and EURs. The upside is definitely there as we recently completed our last well with a 39-foot lateral, 12 stage stimulation and it flowed and is flowing to sales at 16.1 million a day and over 1600 pounds flow casing pressure. We plan to expand our program to approximately 73 horizontal wells in 2010 with a proposed plan of 100 wells in 2011. We will expand our drilling fleet by approximately two rigs per year going forward to meet this goal. We also anticipate that this program will yield over a tripling of our 2010 productions, and a doubling again of our production in 2011.

A newer wrinkle to the Marcellus play has also emerged. As you may recall, we mentioned that future development may be impacted with the potential horizontal completion in the upper Marcellus and the Purcell Limestone. The Purcell lies between the upper and lower Marcellus, in some ways analogous to the middle Bakken in North Dakota. We undertook an initiative to drill horizontal Purcell well last year and just recently completed that well and started flowing back. We are very pleased with the results to date. The well has a 30 day average of 7.3 million cubic foot per day. We ran micro sized survey, as we stimulated the well and found stimulation had predominantly gone to the Purcell and the upper Marcellus. While this is still early, it might suggest that we will be able to access the reservoirs without interfering with our lower Marcellus development. That may mean that additional horizontal wells targeting these intervals will be placed on our current and future pads. While still early, this revelation may suggest an increase in the resource potential on our acreage. Additional testing is obviously planned in the future to evaluate this thesis.

Physical take away and firm pipeline capacity continues to expand. We have recently tweaked our Teel Station and can now physically produce approximately 110 million cubic foot per day. Our Lathrop Station is underway also. Our plan is to have that station at a point free flow into cells by early March, weather permitting. Initial compression set up is expected to complete -- be completed in May capable of flowing 60 million cubic foot per day, at that time with final stage finished, and ready for sales in August at a total rate of 165 million cubic feet per day. The Company's Marcellus operation will have a total physical capacity of 275 million cubic foot per day at that time in August. Remember that we are moving pipeline quality gas, and therefore do not have to install extensive and time consuming liquid stripping plants. Today the Company has 95 million cubic foot per day of thermal pipeline capacity -- 70 million of which is the backhaul arrangement on Tennessee Pipe.

Last night, we announced that we have agreed to a new pipeline expansion to the south that will move a minimum of 150 million cubic foot of our production on a firm basis to Transco. This expansion is expected in the middle of 2011, bringing our firm takeaway capacity at that time -- in the middle of 2011 -- to 275 million cubic foot per day. This is a huge positive for our operation, and our expansion plans for the Marcellus. Our Marcellus operation is the real deal, and this expansion will fit well within our growth plans. Our first vertical well was completed in July of 2007, at about 1 million cubic foot per day. First horizontal -- December 2008 at 6.4 million cubic per day. Production year-end, 2008, 16 million a day, production year-end 2009, 72 million a day, and today, as I have mentioned, we are over 100 million cubic foot a day with a significant backlog of wells ready to be completed. Current production is coming from only 48 wells. Of those, 19 are horizontal. Also we have 1,500 to 2,000 locations remaining to be drilled in this area. We will be in the middle -- we will be in the Marcellus in this area for many years to come.

Now, let move to east Texas -- the focus of our east Texas activity is obviously on the Haynesville Shale, the outstanding results of the common resource Burrows well which we had 42%, and the [Devine Cardell] which we took an overriding royalty interest in, certainly spurred activity in the area. Cabot Oil & Gas drilled its first operated Haynesville horizontal shale well over the new year. The well is at total depth and has been cased. Completion operations are now underway. We will report test results as they're available. We had hoped to report those results today but completion services has tightened considerably in this particular area since the start of 2010. We think it is somewhat a result of the drilled and case wells at the end of 2000 now -- 2009 -- and they are now going to completion. Additionally Cabot is participating with our third Haynesville AMI well where Cabot has 20% working interest and our fourth AMI well where we have 29% working interest spud last week. Additionally we have committed to join three other outside operated wells in the area, and we will spud our second operated well in March. Cabot holds approximately 63,000 gross, 33,000 net acres in the Haynesville play. We are comfortable holding around 50%, 60% working interest, as these wells do eat up a lot of resources at 10 million plus each.

In our Minden area, Cabot has recently completed a confirmation well offsetting the Taylor horizontal test we had drilled last year. This well has a 30 day average of 5.9 million cubic foot per day with estimated gross reserves of approximately 6 Bcf. Our initial well there had an EUR of 6.7 Bcf. Drilling finding costs of these wells is about $1.49 an Mcfe with excellent rate of returns, even at $5. In fact the economics of these wells are second only to our Marcellus wells in the Company portfolio. We have identified at least 50 additional locations on our Minden acreage, and we are currently drilling our third horizontal Taylor well. The Company completed two 2010 Pettet oil wells, with an average IP of 840-barrels a day and 2.1 million cubic foot a day. We have drilled 11 Pettets this year with one well flowing back, two wells completed, two drilling, and four wells to be drilled. In the James, we had a couple of completions in the county line area. These were tested at 8.8 and 7.8 million per day. Four more wells are waiting on completion and four are planned for the rest of 2010.

I am sure you are wondering where and if Cabot would show up in the Eagle Ford play. We have been studying the play for a while, have actually drilled our first well in the [up-dip] portion of the oil [leg]. That well has been cased and is being stimulated as we speak. We will report the results of that operation at a later date. To date, we have 38,000 and about 33,000 net acres under lease, and have another 28,000 acres that we're in final negotiations in the Eagle Ford. This acreage is located either in the dry gas window or the oil window. We continue to lease and expand our position while certainly waiting with anticipation of the results of our first wildcat.

The budget we prepared in October of 2008 -- 2009 -- for our 2000 year end -- year-program using $5.50 for gas, $55 for oil remains intact although we have added an option for additional lease and seismic acquisition. This is contingent on success and if successful, the program would move up our capital program by about $65 million. This forecast would put it at approximately $650 million including the land acquisition. Approximately 70% is going to be focused in the north region. The drilling component remains similar to that reported in October at $443 million. This forecast together with the addition of our 2010 hedges above budget is now estimated at 116% of our anticipated cash flow. With our balance sheet, this is well within our comfort zone. In terms of hedges we did add to our position, which means we are now hedged for 2010 at approximately 33% of our anticipated midpoint production.

One last point, I do want to bring up before I get questions. I would be remiss if I did not take this opportunity to thank Mike Walen and Chuck Smith for the many years of dedicated service to Cabot. Cabot -- Mike has certainly seen and experienced many significant events in our history, most of which he was directly involved in or in some cases, fully responsible for. We want to thank him for all of his efforts. We will miss him but we do have him for a couple of more months. Chuck as our principal accounting officer has seen a lot of change in his tenure in the accounting world and through it all, he always made us comfortable with the final products. And, Chuck, I want to thank you for that also.

Stephanie, with those comments, I will turn it back to you for any questions.

(Operator Instructions). Your first question comes from Michael Jacobs with Tudor, Pickering, Holt.

Thank you, good morning, gentlemen.

Hi, Mike.

Dan, great update and thanks for all the color on both the gathering and take away. As you look to double production in 2010 and 2011, would you expect a wave of completions out of your backlog in May and again in August as you add capacity at Lathrop?

Well, I think we are going to be pretty steady. We will actually -- Michael in 2010 -- we will triple our production. But I would look for a fairly steady progression of completions throughout the year. As I have mentioned we have 22 wells that we are -- that are in the queue for completion as we speak. We continue to drill with our rigs that are in the field right now, and 17 of those 22 being horizontals. But, it is my anticipation that it is not going be back loaded that much.

We do find ourselves at a maximum rate between now and when we get the Lathrop Station fully operational. But we do expect in the middle of March once we get our plumbing hooked up we are not going to have full compression capabilities -- but in March we should be able to enhance and flow through that system about an additional 65 million cubic foot. Then as we move into May, with hooking up all of the compression be able to up and increase that number. I think it is fairly steady and not just backloaded.

That's helpful. As we think about type curve modeling these wells, can you give us any color as to how you are managing these wells as it relates to opening chokes and how you are managing performance as tubing pressure declines.

Yes. I will, and I will let Steve Lindeman also cover that. But, that is being evaluated right now. And the last couple of wells we brought on, we had brought on a little bit slower. And obviously the last well we completed with the 3,900-foot lateral and 12 stage frac, it is flowing at 16 million a day. If we want to have one of those ah-ha rates, it would have been available to us. But we decided not do that. But, Steve would you want to make any comments.

Yes, that's right. We bringing them on line, and not pulling them extremely hard. And we are letting them gradually work their way down the line pressure. What we've seen on some of the wells is as they clean up, the rates actually increase over the first 30 days or so, and then we are just letting them gradually work their way down the line pressure.

That's great. On the $0.51 F&D in the Marcellus, what were the total reserves used in that calculation?

I'm sorry. I didn't hear the question, Mike.

Drilling finding costs.

Yes just the $0.51 F&D in the Marcellus, wondering what the total reserves booked in that $0.51 number there.

The $0.51 calculation, we used 365 Bcf.

And how many total locations.

We have just north of 100 locations in the Marcellus

One last question I promise and I will jump off -- on the 190,000 net acres thinking about the 20,000 to 30,000 that you recently acquired -- what were you paying on a per acre basis and the royalty -- just to fill in that acreage?

Yes, we are still out there active Michael and I am not going into the details with that.

Okay. Thank you.

Your next question comes from the line of Jack Aydin with KeyBanc.

Hi, guys.

Hey, Jack. How are you?

Mike, congratulations, I am going to miss you. But I don't think you are going to miss my questions.

Thanks Jack, appreciate that.

Regarding the classification of parts, what percentage of that was in the east part of the country?

Just a minute, Jack. We're getting some numbers here for you.

While you are getting the number, Mike, how much that Purcell well, how much it cost?

That is our typical $3.6 million to $3.7 million range. It was very consistent with the lower Marcellus.

Okay. How comfortable are you in saying that most of the -- the [parcel is lighter] than all your acreage.

I had that question earlier and with -- of course there's not a lot of vertical logged control in the county even with all of the drilling. But with the data we have at hand it appears that it underlies all of our Susquehanna acreage.

Thanks a lot. Again congratulations, Mike.

Thanks. Here is your answer from Steve on the [PUDs]

Half of it was in the east.

Okay. Thanks. Great report. Thank you.

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

Thank you. Good morning.

Hi Brian.

If your Haynesville wells in St. Augustine county and the Eagle Ford drilling you are doing -- if those wells are successful how are you thinking about how that might your change your CapEx or CapEx allocation plans and would that give you anymore confidence in potentially pursuing additional asset sales.

Well, the high class problem Brian is we have a lot of opportunities to drill. We are managing our balance sheet and capital exposure. We're allocating as we mentioned about 70% to the Marcellus right now and I think that percentage allocation will hold strong just with the results we are seeing in the Marcellus.

As we explore and exploit the Haynesville down in the county line area, and also weighing on results in the Eagle Ford we will have those decisions out ahead of us. And there's certainly multiple options available to us on how we would get our arms around the additional opportunities that we'd see that yield competitive and good returns that we would expect out of the Haynesville and the Eagle Ford. But we are going to tackle that at the appropriate time.

Thank you. And then I guess separately, I wanted to see if you could give some color on your thoughts and activity on a couple of areas you didn't mention -- the Bossier -- middle Bossier -- and then the Marcellus acreage that you have throughout your position outside of the Susquehanna area.

The -- I will turn it over to Mike here in a second but first off, the, the acreage outside the Susquehanna area -- or Susquehanna county -- is very, very few acres in the adjacent counties. So, that whole area when we talk about our operation, say Susquehanna, it is all focused right there, that's where all of our activity is. We do have certainly some legacy acreage in northern West Virginia, that we -- but we have not -- and it is HPB -- and we have not started anything in that particular area for the Marcellus. And, as far as middle Bossier, there is now some increased activity in the middle Bossier and I will let Mike make a comment in regard to that.

Yes, Brian, and I'll just augment Dan's comments. The majority of our acreage outside of Susquehanna county is located just on the far eastern part of Bradford county, northern part of Wyoming counties and far western Wayne county. It really is considered just Susquehanna county if you want to be honest about it.

In the middle Bossier, we have several operators who are proposing middle Bossier tests in our Haynesville area. We have seen some pretty descent rates coming out of these wells with early life still being -- still cleaning up and having early life so we don't know what that might mean. But I fully expect to see Cabot be involved with some middle Bossier tests fairly soon.

Great. Thanks and congratulations Mike.

Your next question comes from Ellen Hannan with Weeden & Company

Morning. Congratulations as well, Mike.

Thanks, Ellen.

A couple of questions just to follow up on the Purcell, you mentioned you think it underlies most of your Susquehanna county acreage. Am I correct in assuming that you had ultimately developed that separately from the Marcellus and do you have a feel or is it too early to say on the decline curve on the lime versus the shale. And how you think that might play out.

It is really too early to tell yet. The well has only been in line for a little over 30 days, 40 days. So it is early but I think what's really relevant is the fact that the stimulation suggested that the fracs are going to be climbing and stimulating the Marcel and the upper Marcellus -- does not appear to have anything growing down into the lower Marcellus and that would certainly suggest going forward that we would need to drill twin wells if you will on the same paths as lower Marcellus to access those reserves. Now this is early time, we don't have a lot of history yet and we only one well, so we have to go forward cautiously. But overall we are pretty excited about the idea that it seems to have worked out and we may be just be stacking more reserves on top of the lower Marcellus potential.

Great. Thank you. And then, one other question, I had, generic question, in terms of your PUD booking. I was curious what was your original internal rule in terms of number of years before the PUD hit the drilling schedule or do you think of it in terms of the percentage of the budget you devote. What is the change there versus what you had been doing versus the new rules.

What I would say is that the majority of our PUDs historically had been still within a five year window with the success that Dan mentioned in the northeast and east Texas. That's deferred some of these opportunities. So that is why, those locations were moved to the probable categories.

The other question I had is in terms of -- how much annual spending you are comfortable with targeting for PUD development.

We have $1.1 billion in the reserve report over the upcoming five years, and if you look at that, that's relatively modest level. I think it is probably maxes out at about $250 million to $300 million in its maximum year over that five year period.

Okay. Thank you very much.

Thank you.

Your next question comes from Andrew [Fullman] with UBS.

Good morning, folks.

Hi Andrew.

I had a question for you on the Purcell line, is that gas bearing? How does it vary, you think between the Marcellus and the lime?

We actually Andrew I think we earlier said we had cored the upper Marcellus, the Purcell, the lower Marcellus. Certainly the rock properties in the lower Marcellus are a little bit superior to the Purcell and the upper Marcellus but still those two zones are excellent source rocks. They show the same type of maturation -- a little bit leaner on the TOC -- but we knew they were gas bearing. We also knew that from our vertical completions in numerous wells in Susquehanna county in these two zones that they would give up gas. The question in our mind wasn't was it gas bearing, was it economic. It was obvious that with this completion that the Purcell and the upper Marcellus are just going to be additive to the economic play up there.

Okay. Great. And then did you also comment on how thick you have seen it up there?

We did not. It is just a member of what we would term the entire Marcellus and interval from the upper contact to the Onondaga. And we've maxed out at approximately 400 foot thick in our drilling, so it is just a piece of that package.

Okay. And then just to reiterate what I think I heard earlier on the call is -- fourth quarter, the Marcellus average was in the 70 million a day range?

We exited 2009 at 72 million a day gross production.

Okay. Will you disclose the average in the queue?

I don't think so, no.

Okay. One question on congratulations on getting some Eagle Ford exposure too. You've grown that resource exposure. But, will you need additional manpower, to go and take on another large acreage position.

I don't think so. We had -- when we did our realignment and brought some folks in from Denver to our Houston office, we have engineers and geologists land men to expand that Eagle Ford play. That was always part of the entire strategy -- was to reallocate to more fully utilize our manpower, so we we are in very good shape that way.

Okay. Excellent. Thank you very much.

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

Thanks. Good morning, gentlemen.

Michael.

You made some comment about lateral length and moving to longer lateral and greater frac stages on your Marcellus wells. Is there a focus in terms of making a move toward longer laterals and greater frac stages for all of the 2010 budget, or is that on an ad hoc basis. And then what does that do for per well costs? The 4500-foot versus your average at 2800-foot.

Well, first off, we have several considerations when we are lengthening our laterals, the objective is going be to determine the optimal length of the laterals, and the optimal spacing of each stimulation stage, and how many stages. Some of that is going to be determined about our acreage position, also -- on how long we can -- to go out and still remain on our acreage. But the objective is to drill each well as efficiently as we possibly can.

In regard to drilling out say 2800 feet or so which was our average of a well so far, to additional 1,000, 1500 feet -- the drilling time on that is minimal. And it will not add significantly the cost of drilling and the additional pipe is not that expensive. The cost really will come in but it is not going to be excessive -- but the cost will increase depending on the number of stages of stimulation that we put in each well.

Okay. So, I guess of the 73 wells that you plan on drilling in 2010, is there a mainly different average lateral length versus those drilled in 2009.

I think you will -- I think it is safe to say that we are going to lengthen our laterals, and increase our stages -- greater than eight stages in the majority of the wells in 2010.

Okay. That's helpful. And then, circling back to an earlier line of questioning -- on the 73 wells in 2010 and the 100 wells in 2011 that are planned, how many are actually budget to be tied in line and brought on production of those wells, and is there a targeted backlog of --

In the 73 wells I think we had maybe 55 to 60 wells that we would turn in line at that period of time. I don't have that just right at my fingertips.

But still that one completion a week is what you talked about before -- ball park.

Yes.

Okay. And then on that Purcell well, any color on it maybe to help us with the decline curve -- a 24 hour IP and then like a 30 day exit as opposed to the full 30 day average?

Well, right now, it would be a 30 day average, it is holding up extremely well. So, we haven't seen anything to marginally change the type of decline curve that this well is going to yield versus the wells we have drilled so far.

That's all helpful. Thanks very much.

Thank, Michael.

Your next question comes from the line of Joe Magner, with Macquarie.

Thank you. Congrats as well to Mike on his way out. My first question just relates to some of the completion delays you mentioned throughout your ops update. How much cushion have you factored into your 2010 growth plans to allow for those types of delays?

Well, every year, we forecast a little bit of a risk profile to our declines and maybe the rates as a matter of course. I don't have the specific number that we have forecast into it. But we certainly have layed a layer of risk in it.

And, then just one fault. You mentioned specifically access to pressure pumping in east Texas as one area where you are seeing some tightness. Are there any other specific things to be on the lookout for. You mentioned a large inventory of deferred completions industry wide, are there other materials or services that stand out that are causing some builders --.

Well, yes. Joe in east Texas, is it is not unique, but it is an area that is seeing the greatest amount of pump pressures necessary to stimulate the Haynesville shales. It's pretty rough on the equipment according to the service companies. And, I think the repair rate of some of that equipment -- plus or minus 10% is a number that we've heard of equipment down, being repaired at any point in time. I think that's exasperated a little bit. You have also had a -- and I think -- this is me speculating somewhat, but the -- just like us, the well that is we drilled and cased in 2009, we are completing those and have completed those wells in January and February as we try to get those turned in line. And so that was a little bit more flurry of a completion activity over and above just the wells that have rigs on them right now.

So I think pumping is -- with the number of horizontal, percentage of horizontal going up compared to the number of rigs being utilized. I think the pumping services is going to need to get more equipment out there and crews and -- so we won't have run away on the costs. Rigs are -- and specifically fit for purpose rigs -- are going to be the rig of choice, up in PA. And it is a long move for some is of the rigs to get up there but we do expect those rates have seen a mild increase in the day rate. But we would expect also us to be able to find the type of rigs that we are using up there also. So we have seen those couple of areas a little bit of an increase on tubulars. Tubulars right now actually are a little bit down from what we had seen in 2009.

Okay. That's helpful. Thank you.

Thank you.

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

Yes, on your east Texas budget -- I know could move some parts around but at least preliminarily or you could just give me net wells, too -- would be going to the Haynesville versus the Pettet, Cotton Valley horizontals and Eagle Ford?

That's a moving target because of the fact that right now we have 11 Pettet wells budgeted and about four gross Haynesville wells budgeted. But with the level of activity increasing for the Haynesville shale, with a lot of the folks around us we are getting numerous AFPs coming in to join them on these Haynesville tests and we will join them. And by doing that we will probably reallocate some capital away from some of the other activities into the Haynesville test.

Okay and how many more Cotton Valley horizontals do you plan on drilling.

Actually, we just reached TV -- TD -- on our last one. For the year.

Okay and a couple of more questions. On the follow up well for the Purcell limestone, you said you are doing to drill some more tests. Is that really soon or is that second half of the year, when do you plan on doing that?

We really haven't decided where and when we will drill those follow up tests. We will work those into the program, in '10 and '11.

Okay. Thank you. The last question, the type curve for the 5.5 Bcf type curve for the Marcellus -- is that a 30 year life and what is your long term decline assumption?

That would be about 40 year life and our determine decline rate is 4%.

Okay. That's all for me. Thank you.

Thank you.

Let me just expand on a little bit Marshall, with regard to drilling the wells and how we allocate capital, for example the horizontal Taylor wells, that is -- in Minden area -- that is all HBP acreage and we wanted to get a -- value that and look at the consistency and some of our technology we are using to test those Taylor horizontals. We like the economics as I've mentioned, but it is all HBP acreage, where we are drilling some of the other drills, we are capturing primary term acreage, which is an objective on how we are allocating our capital.

Your next question comes from the line of Biju Perincheril with Jefferies.

Hi. Good morning. Just a couple of questions, on the production from out of the Marcellus, just to clarify, did I hear you right that between now and March, the production is going to be more or less you will stay above that 100 million a day until the next infrastructure, is that --

Our plan is to continue to complete a well. We -- and we have capacity in our Teel Station right now. Our [compressure] station there -- between 100 million and 110 million now that we have tweaked it and that is our capacity out there at this stage.

Okay. And so what is your net production now?

It is -- What is your definition of net production.

What's your report?

We are producing over 100 million a day and the majority, well all of the leases we are producing right now have a one-eighth lease royalty.

Okay. There's no minor working interest partners.

No all of it is 100% Cabot wells.

Okay. Perfect. That's all I was looking for. And when you talked about doubling or tripling production this year and doubling again in 2011, is that a year-over-year number or exit over exit.

That's year-over-year.

Okay. And can you give us what the '09 volumes were average?

We were about 11 apiece.

Got it. Okay. Then, on this Purcell test, was that next to an existing lower Marcellus well, or.

It was just in the middle -- the northern end of our development area. So yes we were surrounded by a bunch of lower Marcellus completions.

At this point, is there any way to tell how much contribution you are getting from the upper Marcellus?

Well, since the frac did propagate in the upper Marcellus, we do think that part of that rate is coming out of the upper Marcellus as well as the Purcell. So in that sense it makes the story better, because now we see that we are going to be able to access those upper Marcellus reserves. Earlier with just a lower Marcellus frac, we were not seeing those reserves.

Got it. And so with just two wells now you should be able to access all three zones?

We would hope so, we just have to wait and see.

Okay. That's all I had. Thank you very much.

Thank you.

Your next question comes from Ray Deacon with Pritchard Capital.

Hi Mike. I was wondering if I could ask you with your comments about the Haynesville and difficulty getting frac crews -- how much completion costs may have gone up over the last couple of months. I may have missed this but how many Eagle Ford wells do you have planned for this year?

Frac costs for the -- in the Haynesville have gone up considerably over the last six to eight months, and that's all due to the lack of equipment or the equipment being tied up. But it is up over 50% in the last six to nine months for just frac costs. As far as Eagle Ford we will get this well completed and we will see how it works out and as Dan said we are stimulating that well today and should be done in the next few days and I think we will just hold off and decide how many wells we are going to drill down there for the rest of the year and next year until we see some history there.

Got it. Okay. And are you -- in the Purcell what will dictate the pace of development there? Going forward, you have only got one well. But how many wells do you think you could have by this time next year say?

We are going to moving forward right now with our 2010 program -- 73 wells we anticipate to be majority of those in the lower Marcellus, and as we continue to gather data through our micro size and drilling maybe a couple of additional wells in the shallower section. But, predominantly, right now, we are going to focus on the lower Marcellus and we will continue to continue on our thesis on the Purcell and upper Marcellus.

Got it. Thank you very much.

Thank you.

Your next question comes from [Drew Vincor] with Lazard Capital Markets.

Hi guys, just looking at your production growth guidance for the year -- it looks like in the second half, the growth drops off pretty sharply. Can you provide any color on what that might be related to?

This is Scott Schroeder. Again, this is the guidance we established when we started the year and picking up on a comment or question earlier that we didn't quantify. We have risk -- the volumes in terms of just from a purely execution perspective not from a geological perspective. Again we had rather stay firm to our guidance and have the ability to ratchet it up as we continue to have the kind of success we have recently had versus moving it up at this point in time and then falling short.

So there's no specific one or two or even three things to point to as it relates to that. It is just the initial guidance we have put out that with we are standing by at this point in time but with continued success those numbers will move up later in year.

Okay. So, maybe no infrastructure constraints?

No.

Okay. Thanks.

(Operator Instructions). Your next question is a follow up from Michael Jacobs.

I forgot to congratulations Mike. That's my excuse for jumping back in.

Appreciate it.

Okay. On the Marcellus capital spent last year, can you break that apart for us in terms of development CapEx versus exploration versus infrastructure and land as well?

We can.

While you are looking for it, I can ask another one if that makes sense. On the -- just on the 190,000 net acre position, how high can that do over time if you filled in your entire position, and maybe added a little bit more?

Well, in Susquehanna and others certainly in the Susquehanna area, there is going to be just a few areas that have open acreage in Susquehanna. If there's any significant adds to that number, it's probably going to come in the form of somebody showing their interest or something like that. Because the majority of the acreage in that area has been leased.

So we shouldn't expect to see you guys going up to say 250,000 net acres.

It is not going happen on an organic leasing program, because there's not that much available acreage in Susquehanna that is not leased. If -- saying it differently -- if the right opportunity came along, Michael and somebody was going to sell 50,000-acres and we could negotiate the right deal for Cabot, we would certainly entertain that opportunity.

That makes sense. How do you think about stepping into that position from an infrastructure standpoint and also from testing a greater portion of your acreage over the next couple of years?

Well we are entirely comfortable with the infrastructure aspect of it. We have a couple of compressor sites, we laid over 25 miles of pipe and continue to expand laying pipe. We're talking about multiple options to secure midstream support on getting our gas to pipelines. We just mentioned the deal where we got another 150 million plus a day, take away in this particular area. There's a couple of other pipes that is in the northern part of our acreage position, that are laying right through the middle of our pipelines -- I mean our acreage that we are talking to -- or right now. So, we are entirely comfortable with the infrastructure. Keep in mind we are blessed with a absolute perfect maturation in this particular area as far as the gas is concerned. We have no water, and no liquids, and so it is just pure gas, high percentage methane gas pipeline quality gas, so all we have to do is get a pipeline to it.

Great.

Michael, on the east expenditure -- or the north expenditures, [200] was drilling, [125] was leasing -- new leases, roughly [35] was the infrastructure pipeline, and then there was about [8] for some seismic and then there's a handful of just other expenses.

The last question, since I haven't asked a Haynesville question -- just a clarification on the 50% increase in frac costs, is that on a per stage basis, are you doing bigger fracs there and really what I am trying to get to is how much is purely service cost inflation?

It is all service cost inflation. The total job has gone up about 50%, and that is where we are are keeping our jobs -- our standard Haynesville type frac -- 12 stages to 15 stages, and what you see out there everybody is doing.

Thank you.

At this time, there are no further questions in the queue.

Thank you. I appreciate everybody's interest in Cabot. We have a significant program that we are going be able to report as we go throughout the year. I look far to visiting with you in April. Thank you.

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