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Cabot Oil & Gas Corporation (NYSE:COG)

Q4 2009 Earnings Call

February 22, 2010 9:30 am ET

Executives

Dan Dinges – Chairman, President, Chief Executive Officer

Michael Walen – Senior Vice President, Chief Operating Officer

Scott Schroeder – Vice President, Chief Financial Officer

Analysts

Michael Jacobs – Tudor Pickering Holt

Jack Aydin – Keybanc Capital Markets

Brian Singer – Goldman Sachs

Ellen Hannan – Weeden & Co.

Andrew Coleman – UBS

Michael Hall – Wells Fargo

Joseph Magner – Macquarie

Marshall Carver – Capital One Southcoast

Biju Perincheril – Jefferies & Co.

Raymond Deacon – Pritchard Capital

[Drew Vinker – Lazard Capital Markets]

Operator

I would like to welcome everyone to the Cabot Oil & Gas fourth quarter and year end 2009 conference call. (Operator Instructions) I would now like to turn the conference over to Mr. Dan Dinges, Chairman, President and CEO.

Dan Dinges

Good morning. Thanks for joining us for this 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 forward-looking statements included on the press release as it applies 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’ll 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’ll 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 claims earnings perspective net income was $178 million. The selected items include a loss of sale, impairments, stock compensation and mark to market for 2012 basis hedges. Debt decreased slightly from 2008 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 conditions, these two 2009 results fall into the top quartile for our historic results.

Straight to the reserve metrics, from a value added perspective, one of the key metrics to any organization’s growth and in our industry is the ability to stack up reserves at an economic investment level. Cabot once again was successful, growing reserved 6% year after 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 reduction and provision adjustments for the year all from our organic effort. With all of the 2009 increases coming from our organic program, the corresponding drilling refining cost was $0.83 per mcfe.

Let me get a bit more granular as it relates to our reserves. Clearly there is significant noise in the interpretation of the new rules. What Cabot did was remove all 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 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 cost 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 1.2 Tcfe. The company replaced 450% of its production at refining costs of $1.28 per mcfe. The refining cost includes a capital investment on leases including Susquehanna county which will certainly pay dividends for years to come.

Excluding these lease investment, the company’s refining cost fell below the $1.00 mark at $0.97 per Mcfe. The company still maintains a modest pud booking level of only 36%. Having 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 reserve by 222 Bcfe which is partially offset by 22 Bcfe positive performance revisions. This revision reflects two requirements. First, instead of using the December 31 price of $5.79, under the new SEC rules, the company was valued at the average price for the first of each month which is $3.87 for 2009.

This one-third drop in natural gas price reduces the company’s 2009 reserved by 102 Bcfe all being tail reserves. Clearly Cabot’s reserve bookings at 98% natural gas adversely impacted year end reserves more so than [oily names] that actually 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 reserves must be developed within five years from initial booking. With 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 books 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 these related to areas where the acreage is held by production.

For 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, with 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 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 for Cabot as the company was almost purely a resource driven company. It was the first year where the vast majority of our investment was earmarked for repeatable low risk targets in east Texas and the Marcellus share 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’s 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 renewal 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 our sell off acreage is not created equally. Subsequently, we were able to mass essentially a single block of Marcellus acreage. We’re confident that this strategy will result in growing efficiencies in 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 costs have stayed relatively constant between $3.5 million and $3.8 million completed depending on the length of laterals and the 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 of approximately 62% to 21 days. More needs to be done to reduce further the cost, but we view this accomplishment as certainly a good start.

Now let’s talk about the bottom line production and reserves. We’re 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 of way and stream crossing permit somewhat reduced our 2009 exit rates.

We estimate that just waiting on the stream crossing 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 cubit foot of gas per day flowing through our Teal 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 de-risked our entire acreage block.

Is there is room for enhancing our program? Certainly we think there is. We have achieved these results while completing laterals that average only 2,800 feet so far with an average of eight stimulation stages. As we lengthen our laterals and we recently finished one at 4,500 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 DUR’s.

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 at over 1,600 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 new 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 and in some ways analogous to the middle Bakken in North Dakota. We undertook an initiative to drill a horizontal Purcell well last year and just recently completed that well and started flowing back.

We’re very pleased with the results today. The well has a 30 day average of 7.3 million cubit foot per day. We ran a micro size survey as we stimulated the well. In fact now the 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 pad.

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 fuel 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 sales by early March weather permitting, and the initial compression set up is expected to be completed in May and 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 foot per day.

With the Marcellus operation, we’ll 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 did not have to install extensive and time consuming liquid stripping plants.

Today, the company has 95 million cubic foot per day of pipeline capacity, 70 million of which is the back haul 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 production on a firm basis to Transco.

This expansion is expected in the middle of 2011 bringing our firm take away 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.

Marcellus operation is the real deal and this expansion will fit well within our growth plan. Our first vertical well was completed in July of 2007 at about one million cubic foot per day. The first horizontal December ’08 at 6.4 million cubit foot per day.

Production at year end 2008, 16 million a day; production year end 2009 72 million a day and today, as I’ve mentioned, we are over 100 million cubit 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’ll be in the Marcellus in this area for many years to come.

Now let’s move to east Texas. The focus of our east Texas activity is obviously on the Haynesville shale. Standard results of the common resource bodes well of which we have 42% and the Devon Cardell which we took an overriding royalty interest certainly spurred activity in the area.

Cabot Oil & Gas drilled its first operated Haynesville shale oil 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 are available.

We had hoped to report those results today, but completion services have tightened up considerably in this particular area since the start of 2010. We think it’s somewhat a result of the drill to case wells at the end of 2009 and 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 from last week. Additionally, we have committed to join three other outside operated wells in the area and will start our second operated well in March.

Cabot holds approximately 63,000 gross, 33,000 net acres in the Haynesville play. We’re comfortable holding around 50% to 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 complete a confirmation well offsetting the Taylor horizontal test we had drilled last year. This well has a 30 days average of 5.9 million cubit foot per day with estimated gross reserves of approximately 6 bcf. Our initial well up there had a DUR of 6.7 bcf.

Drill refining costs of these wells is about $1.49 and Mcfe with excellent rate of returns even at $5.00. In fact, the economics of these wells second only to our Marcellus wells in the company portfolio. We’ve identified at least 50 additional locations on our Minden acreage and we’re currently drilling our third horizontal well.

The company completed two 2010 Pettit oil wells with an average IP of 840 barrels a day and 2.1 million cubic foot a day. We have drilled 11 Pettit’s this year with one well flowing back to wells complete, two drilling and four wells to be drilled.

At James we had a couple of completions in the county line area. These wells 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’m sure you’re wondering where and if Cabot would show up in the Eagleford play. We have been studying the play for awhile. We’ve actually drilled our first well in the up dip portion of the oil leg. That oil 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 Eagleford. 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 the results of our first wildcat.

The budget we prepared in October of 2009 for our 2010 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 mid point production.

On 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. Mike has certainly seen and experienced many significant advances 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 his efforts. We’ll miss him, but we do have him for a couple 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 product. And Chuck I want to thank you for that also.

Question-and-Answer Session

Operator

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

Michael Jacobs – Tudor Pickering Holt.

Great update and thanks for all the color on both the gathering and take away side. As you look t 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?

Dan Dinges

I think we’re going to be pretty steady. Actually in 2010 we’re going to triple our production. But I would look for a fairly steady progression of completions throughout the year. As I mentioned, we have 22 wells 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’s my anticipation that it’s not going to be back loaded that much. We do find ourselves kind of 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’re 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.

And then as we move into May with hooking up all the compression be able to increase that number. So I think it’s going to be fairly steady and not just kind of back loaded.

Michael Jacobs – Tudor Pickering Holt

As we think about type curves modeling these wells, can you give us any color as to how you’re managing these well as it relates to opening chokes and how you’re managing performances as tubing pressure declines?

Dan Dinges

That’s 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’s flowing at 16 million a day. If we wanted to have one of those ah ha rates it would have been available to us, but we decided not to do that.

Steve Ledderman

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

Michael Jacobs – Tudor Pickering Holt

On the $0.51 S&D on the Marcellus what were the total reserves used in that calculation?

Scott Schroeder

In the $0.51 calculation we used 365 bcf.

Michael Jacobs – Tudor Pickering Holt

In how many total locations?

Scott Schroeder

Just north of 100 locations in the Marcellus.

Michael Jacobs – Tudor Pickering Holt

On the 190,000 net acres, thinking about the 20,000 to 30,000 that you acquired, what were you paying on a per acre basis and the royalty to fill in that acreage?

Dan Dinges

We’re still out there active. I’m not going to go into details of that.

Operator

Your next question comes from Jack Aydin – Keybanc Capital Markets.

Jack Aydin – Keybanc Capital Markets

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

Dan Dinges

We’re getting the numbers for you.

Jack Aydin – Keybanc Capital Markets

How much did the Purcell well cost?

Michael Walen

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

Jack Aydin – Keybanc Capital Markets

How comfortable are you in saying that the Purcell is light under all your acreage.

Michael Walen

I had that question earlier and with of course there’s not a lot of vertical log control in the county even with all the drilling but with what we have in hand, it appears that it underlies all of our Susquehanna acreage.

Here’s your answer from Steve on the puds.

Scott Schroeder

Half of it was in the east.

Operator

Your next question comes from Brian Singer – Goldman Sachs.

Brian Singer – Goldman Sachs

If your Haynesville wells in St. Augustine County in the Eagleford willing that you’re doing, if those wells are successful, how are you thinking about how that might change your CapEx or CapEx allocation plans and would that give you any more confidence in potentially pursuing additional asset sales.

Dan Dinges

The high class problem we have 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 would hold strong just with the results that we’re seeing in the Marcellus.

As we explore and exploit the Haynesville down in the county line area, and also waiting on results on the Eagleford, we’ll have those decisions out ahead of us and there is certainly multiple options available to us on how we would get our arms around the additional opportunities that we see that yield competitive and good returns that we’d expect at the Haynesville and the Eagleford but we’re going to tackle that at the appropriate time.

Brian Singer – Goldman Sachs

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 Middle Bossier and then the Marcellus acreage that you have throughout your position outside of the Susquehanna area.

Dan Dinges

I’ll turn it over to Mike here in a second but first off the acreage outside the Susquehanna County is very, very few acres and the adjacent counties. So that whole area where we talk about our operations in Susquehanna, it’s all focused right there and that’s where all of our activity is.

We do have some legacy acreage in Northern West Virginia but we have not started anything in that particular area for the Marcellus. As far as Middle Bossier, there is now some increased activity in the Middle Bossier and I’ll let Mike make a comment in regard to that.

Michael Walen

The majority of our acreage outside of Susquehanna County is just located on the far eastern part of Radford County, northern part of Wyoming County and far western Wayne County so it really is considered us Susquehanna County if you really want to be honest about it.

The Middle Bossier, we’ve got several operators who are proposing Middle Bossier tests in our Haynesville area. We’ve seen some pretty decent rates coming out of these wells with early life still kind of cleaning up and what that might mean, but I fully expect to see Cabot be involved with some Middle Bossier tests fairly soon.

Operator

Your next question comes from Ellen Hannan – Weeden & Co.

Ellen Hannan – Weeden & Co.

Just to follow up on the Purcell, you mentioned that you think it underlies most of your Susquehanna acreage. Am I correct in assuming that you would ultimately develop that separately from the Marcellus and do you have a feel, is it too early to say on the decline curve on the line versus the shale, how you think that might play out.

Michael Walen

It’s really too early to tell yet with the well going in line for a little over 30 to 40 days, so it is early. But it think what’s really relevant is the fact that the stimulation suggested that the fracs are going to be climbing and stimulating the Marcellus and the upper Marcellus. It doesn’t appear to have anything that’s going downward into the lower Marcellus and that would certainly suggest going forward that we would need to drill twin wells on the same path as lower Marcellus to access those reserves.

Now this is early time. We don’t have a lot of history yet and we only have one well so we still have to go forward cautiously. But overall, we’re pretty excited about the idea it seems to have worked out and we may be just stacking more reserves on top of the lower Marcellus potential.

Ellen Hannan – Weeden & Co.

In terms of your booking, I was curious as to 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 your budget you devote to pud drilling. What is the change there versus what you had been doing versus the new rules?

Michael Walen

What I would say is that the majority of our puds historically had still been within a five year window with the success that Dan mentioned in the Northeast and East Texas. That’s deferred some of these opportunities and so that’s why those locations were moved to the probably categories.

Ellen Hannan – Weeden & Co.

In terms of how much annual spending you’re comfortable with targeting for pud development?

Michael Walen

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

Operator

Your next question comes from Andrew Coleman – UBS.

Andrew Coleman – UBS

I had a question on the Purcell line. Is that gas bearing or how does it vary do you think between the Marcellus and the line?

Michael Walen

Actually we earlier said that 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 gas bearing. It was an economic, and 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.

Andrew Coleman – UBS

Did you also comment on how thick you’ve seen it up there?

Michael Walen

We did not. It’s a member of what we would term the entire Marcellus interval from the upper contact to the Anadarko and we’ve maxed out at approximately 400 thick in our drilling. So it’s just a piece of that package.

Andrew Coleman – UBS

What I think I heard earlier on the call, does fourth quarter Marcellus average was in the $70 million a day range?

Michael Walen

We exited 2009 at $72 million a day gross production.

Andrew Coleman – UBS

Will you disclose the average in the Q?

Scott Schroeder

No.

Andrew Coleman – UBS

One question on the transition of getting front exposure too, you’ve got that resource exposure, but will you need additional manpower to go take on another large acreage position?

Michael Walen

I don’t think so. When we did our realignment and brought some folks in from Denver to our Houston office, we have engineers and geologists, land men available to expand that Eagleford play. That was always part of the entire strategy was to reallocate to more fully utilize our manpower to we’re in very good shape that way.

Operator

Your next question comes from Michael Hall – Wells Fargo.

Michael Hall – Wells Fargo

You made some comment about lateral length and moving to longer lateral and greater fracs stages on your Marcellus well. Is there a focus in terms of making a move towards longer laterals and greater frac stages for all of the 2010 budget or is that kind of on an ad hoc basis and then what does that do for well costs, that 4,500 foot versus your average at 2,800 foot?

Dan Dinges

First off, we have several considerations when we are linking our laterals. The objective is going to 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 by our acreage position also on how long we can 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 2,800 feet or so which was our average of wells so far to additional 1,000 to 1,500 feet, the drilling time on that is minimal and it will not add significantly to the cost of drilling, and the additional pipe is not that expensive. The cost really will come in but it’s not going to be accepted, but the cost will increase depending on the number of stages of stimulation that we put in each well.

Michael Hall – Wells Fargo

So of the 73 wells you plan on drilling in 2010 is there a different average lateral length versus those drilled in 2009?

Dan Dinges

I think it’s 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.

Michael Hall – Wells Fargo

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 budgeted to be tied in line and brought on production of those wells and their targeted backlog?

Dan Dinges

Of the 73 wells I think we had maybe 55 to 60 wells that we would turn inline at that period of time. I don’t have that right at my fingertips.

Michael Hall – Wells Fargo

But still that one completion a week is maybe what you talked about.

Dan Dinges

Yes.

Michael Hall – Wells Fargo

On the Purcell well, any color to help us with the decline curve, the 24 hour rrp and then the 30 day exit as opposed to the full 30 day average.

Dan Dinges

Right now it would be 30 day average. It’s holding up extremely well so we haven’t seen anything to markedly change the type of decline curve that this well is going to yield versus the wells we’ve drilled so far.

Operator

Your next question comes from Joseph Magner – Macquarie.

Joseph Magner – Macquarie

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

Dan Dinges

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’ve forecast into but we have certainly laid a layer of risk in it.

Joseph Magner – Macquarie

You mentioned specifically access to pressure pumping in east Texas as one area where you’re 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 visibility pressures?

Dan Dinges

Yes. In east Texas, it’s not unique but it is an area that is seeing the greatest amount of pump pressures necessary to stimulate the Haynesville shale. It’s pretty rough on the equipment according to the service companies. And the repair rate of some of that equipment has plus or minus 10% is a number that we’ve heard of equipment down being repaired at any point in time.

So I think that’s exasperated a little bit. This is me speculating somewhat, but just like us, the wells that we drilled encased in 2009, we are completing those and have completed those wells in January and February as we try to get those turned in line. So that was a little bit more flurry of completion activity over and above just the wells that have rigs on them right now.

So I think pumping is with a number of percentage of horizontal rigs going up compared to the number of rigs being utilized, I think the pumping service is going to need to get more equipment out there and crews so we won’t have runaway on the cost.

Rigs are, and specifically fit for purpose rigs are going to be the rig of choice up in PA and it’s a long move for some of the rigs to get up there, but we do expect those rigs have seen a mild increase in the day rate, but we would expect also to be able to find the type of rigs that we’re using up there also.

So we have seen those couple of areas a little bit of an increase. On tubular, tubular right now are actually a little bit down from we had seen in 2009.

Operator

Your next question comes from Marshall Carver – Capital One Southcoast.

Marshall Carver – Capital One Southcoast

On your east Texas budget, I know you could move some parts around but at least preliminarily how much of that would be going, or if you could just give me net wells, would be going to the Haynesville versus the Pettit, Conn Valley horizontals in Eagleford?

Dan Dinges

That’s kind of a moving target because of the fact that right now we have 11 Pettit 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 AFB’s now coming in to join them on these Haynesville tests and we will join them.

And by doing that, we’ll probably re-allocate some capital away from some of the other activities into the Haynesville test.

Marshall Carver – Capital One Southcoast

How many Conn Valley horizontals do you plan on drilling?

Dan Dinges

Actually, we’ve just reached TD on our last one for the year.

Marshall Carver – Capital One Southcoast

On the follow up well for the Purcell line, you said you’re going to drill some more tests. Is that really soon or is that second half of the year? When do you plan on doing that?

Dan Dinges

We haven’t really decided where and when we’re going to be drilling those follow up tests. We’ll work those into the program in ’10 and ’11.

Marshall Carver – Capital One Southcoast

The tight curve for the 5.5 bcf for the Marcellus, is that a 30 year life and what’s your long term decline assumption?

Dan Dinges

It would be about 40 year life and our terminal decline rates 4%.

Let me just expand a little bit in 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 value that and look at the consistency and some of our technology that we’re utilizing to test those Taylor horizontals. We like the economics as I’ve mentioned, but it is all HBP acreage.

Where we’re drilling some of the other wells, we are capturing term acreage which is an objective on how we’re allocating our capital.

Operator

Your next question comes from Biju Perincheril – Jefferies & Co.

Biju Perincheril – Jefferies & Co.

On the production from the Marcellus, just to clarify, did I hear you right that between now and March the production is going to stay above that 100 million a day until the next leg of infrastructure.

Dan Dinges

Our plan to is continue to complete a well a week and we have capacity in our Teal Station right now. Our compressor station there is between 110 million now that we’ve tweaked it and that is our capacity out there at this stage.

Biju Perincheril – Jefferies & Co.

What’s your net production now?

Dan Dinges

What is your definition of net production?

Biju Perincheril – Jefferies & Co.

What you report.

Dan Dinges

We’re predicting over 100 million a day and all the leases that we’re producing on right now have a one-eighth lease royalty.

Biju Perincheril – Jefferies & Co.

And there are no minor working interest partners?

Dan Dinges

No. All of it is 100% Cabot.

Biju Perincheril – Jefferies & Co.

When you talked about doubling or tripling production this year and doubling again in 2011, is that a year over year number?

Dan Dinges

That’s year over year.

Biju Perincheril – Jefferies & Co.

Can you give us what ’09 volumes were average?

Dan Dinges

We’re about 11 B’s.

Biju Perincheril – Jefferies & Co.

On this Purcell test, was that next to an existing lower Marcellus well?

Michael Walen

It was just right in the middle, kind of the northern end of our development area so we were surrounded by a bunch of lower Marcellus completions.

Biju Perincheril – Jefferies & Co.

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

Michael Walen

The frac did propagate up there 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, this makes the story better because now we see that we’re going to be able to access those upper Marcellus reserves earlier with just a lower Marcellus frac. We were not seeing those reserves.

Biju Perincheril – Jefferies & Co.

So with just two wells, now you should be able to access all three zones.

Michael Walen

We would hope so. We’ll just have to wait and see.

Operator

Your next question comes from Raymond Deacon – Pritchard Capital.

Raymond Deacon – Pritchard Capital

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

Michael Walen

Frac costs 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’s up over 50% in the last six to nine months for just frac costs.

As far as Eagleford, we’re going to get this well completed and we’ll see how it works out and as Dan said, we are stimulating that well today and should be done in the next few days. I think we’ll just hold off deciding how many wells we’re going to drill down there for the rest of the year and next year until we see some history there.

Raymond Deacon – Pritchard Capital

In the Purcell, what will dictate the pace of development there going forward? You’ve only got one well but how many wells do you think you could have by this time next year?

Michael Walen

We’re moving forward right now with our 2010 program, 73 wells. We anticipate the majority of those to be 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 predominately right now we’re going to focus on the lower Marcellus and we’ll continue on our thesis on the Purcell and upper Marcellus.

Operator

Your next question comes from [Drew Vinker – Lazard Capital Markets]

[Drew Vinker – Lazard Capital Markets]

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

Scott Schroeder

This is the guidance that we established when we started the year, and picking up on a comment or question earlier that we didn’t quantify, we do have risk. We have risk in the volumes just in terms of a purely execution perspective, not from a geologic perspective.

We’d rather stay firm to our guidance and have the ability to ratchet it up as we continue to have the kind of success we’ve 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’s just the initial guidance we’ve put out that we’re standing by at this point in time but with continue success those numbers will move up later in the year.

[Drew Vinker – Lazard Capital Markets]

So maybe no infrastructure constraints?

Scott Schroeder

No.

Operator

Your next question comes from Mike Jacobs – Tudor Pickering Holt.

Mike Jacobs – Tudor Pickering Holt

I forgot to congratulate Mike. On the Marcellus capital spent last year can you break that apart for us in terms of some in CapEx versus exploration versus infrastructure and land as well?

Michael Walen

Yes. We can.

Mike Jacobs – Tudor Pickering Holt

While you’re looking for it I can ask another question. On the 190,000 net acre position, how high could that go over time if you filled in your entire position and maybe added a little bit more?

Michael Walen

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

Mike Jacobs – Tudor Pickering Holt

So we should expect to see you going up to 250,000 net acres?

Michael Walen

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

Mike Jacobs – Tudor Pickering Holt

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

Dan Dinges

We’re entirely comfortable with the infrastructure aspect of it. We have a couple of compressor sites. We’ve laid over 25 miles of pipe and continue to expand laying pipe. We’re talking about multiple option to secure mid stream 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 are a couple of other pipes that are in the northern part of our acreage position that are laying right though the middle of our acreage that we’re talking to right now.

So we’re entirely comfortable with the infrastructure. Keep in mind we’re blessed with an absolute perfect maturation in this particular area as far as the gas is concerned. We have no water and no liquids so it’s just pure gas, high percentage methane gas, pipeline quality gas, so all we have to do is get a pipeline.

Scott Schroeder

On the north expenditures, $200 million was drilling, $125 million was leasing, new leases, roughly $35 million was the infrastructure, pipeline and then there was about $8 million for some seismic and there’s a handful of just other expenses.

Mike Jacobs – Tudor Pickering Holt

On the Haynesville, just a clarification on the increase in frac costs, is that on a per stage basis or are you doing bigger fracs there and what I’m trying to get to is how much is purely service cost inflation?

Dan Dinges

It’s all service cost inflation. For the total job it’s gone up about 50% and that’s where we’re keeping our jobs our standard Haynesville frac. 12 to 15 stages and what you see out there that everybody is doing.

Operator

There are no further questions.

Dan Dinges

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

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Source: Cabot Oil & Gas Corporation Q4 2009 Earnings Call Transcript
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