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Cabot Oil & Gas Corp. (NYSE:COG)

Q4 2007 Earnings Call

February 14, 2008 9:30 am ET

Executives

Dan Dinges - Chairman, President and CEO

Mike Walen - COO

Scott Schroeder - CFO

Jeff Hutton - VP of Marketing

Analysts

Brian Singer - Goldman Sachs

Nicholas Pope - JPMorgan

Eric Hagen - Merrill Lynch

David Adams - Jefferies and Co.

Ray Deacon - BMO Capital Markets

Jack Aydin - KeyBanc Capital Markets

Kevin Claire - Bear Stearns

Operator

Good morning. My name is Holly, and I will be your conference operator today. At this time, I would like to welcome everyone to the Cabot Oil & Gas fourth quarter 2007 conference call. (Operator Instructions)

I would now like to turn the conference over to Mr. Dinges, Chairman, President and Chief Executive Officer. Please go ahead, sir.

Dan Dinges

Thank you, Holly. Good morning. I appreciate you joining us for Cabot's year end teleconference call. To answer any questions you might have, I have with me today several members of our management team; Mike Walen, Chief Operating Officer; Scott Schroeder, our CFO; Jeff Hutton, our VP of Marketing; and Chuck Smyth, our VP and Controller.

Before we start, let me say that the statements regarding forward-looking information included in the press release is applied to my comments today. As you all are aware, Cabot issued two solid press releases last night, one with financial and statistical highlights for the year end, and the other reporting achievements in our operations, both illustrating the strength of our program and our ability to create value for the shareholder.

I feel one of the company's bottom line value creation ability, is to add to its reserve base in an efficient manner. Therefore, I am pleased to start the discussion with our year end reserve numbers.

Cabot increased its total crude reserves 14% over 2006 year end levels to a record 1.616 Tcfe of gas. We had over 280 Bcfe added through our organic program, plus 4 Bcfe acquired, and by all accounts that stacks up as a pretty good year. Our crude reserve breakdown at year end was 48% in the East, 30% in the West, 20% in Gulf Coast and 2% in Canada.

As some of you know, Cabot has a deep inventory of opportunities, with an estimated 10,000 plus locations and over 5 Tcfe of unrisked resource potential, which, by the way, does not include any of the more sales potential that we have and that we are just scratching the surface of, which I will discuss later on.

In regard to the efficiency of our operation, this last year, and going forward, our goal is to add new reserves for about $2 per Mcfe all-in and I am pleased to report we are able to achieve that goal with an all-in finding cost of $2.07 per Mcfe.

I believe that all the reports for the year end, that Cabot's organic 334% reserve replacement at around $2 all-in finding costs, with no movement in our PUD percent, will stack up to be a very good year in relation to our peers. And I do look forward to being able to duplicate or improve all these numbers in 2008.

In regard to production, as we indicated in the press release, our absolute production volumes were down slightly between comparable years, due to the nine months production, we realized in 2006 that we sold. However, I am also okay with our pro forma production growth of 14% increase over last year, making it the second consecutive year of pro forma double-digit production growth, following our portfolio rationalization.

I will add that our production expectations were affected by Rockies weather, the nitrogen issues that we had in the East in our hurricane project, and some of the slow well connects we've experience in the East.

With our organic focus clearly both our production and reserve growth though has been driven by 96% success rate in our 461 well 2007 drilling program.

Financially, the company again reported solid net income of $161.9 million, or $1.67 per share after remove a small impairment in gain on sale activity. This level of net income was Cabot's second highest for any full year period, and was exceeded only by last year's effort.

Related pricing from hedging, Cabot experienced a $0.99 per Mcf pickup for the year, and a $0.97 per barrel decline for oil as a result of the company's hedging position. Cabot's overall hedge position is highlighted on our website. And for 2008, we are now approximately 50% hedged with an average floor or swap price of $8.19 per Mcf. We have also initiated a position in 2009, with six colored contracts. Four of the six are in our West Region where we have higher basis, but we still are realizing a floor averaging $7.98 per Mcf. All of our 2009 hedges are at the specific sales point for gas, and does include our basis. These hedges were placed with an average NYMEX Mcf price of $9.60.

Our expenses overall for the year were basically flat with only a 1% increase over last year. DD&A was up due to the cost related to capital investments in the last year inflationary period, offset, however, by lower exploration as we focused strategically on exploration and lower stock compensation.

Now moving to the meat of our discussion, our operations. The main focus of our 2008 program will be in two areas, East Texas, and the east in Appalachia. Within these two areas, it encompasses a couple of the hardest places in the industry today. Cabot will allocate over 80% of our capital to these two areas. And, with many of your questions in the few months being directed to East Texas and Appalachia, I will spend most of our operations discussion in these areas. However, though we are heavily focused in these two areas, I do want mention that our Mid-Continent area does continue to add value through its successful development program in the Morrow and Chester, including the largest program in this area for several years with over 65 wells scheduled.

Also with stabilizing prices in the Rockies, we are looking at expanding our drilling program on the Moxa Arch for 2008 program. Additionally, our Canadian effort will remain small at this time focused mainly in Hinton and Musreau.

Now moving to East Texas, the County Line project has become a premier developmental project in the company. The consistent production growth, nice reserve additions and an excellent return on capital in the horizontal James Lime at County Line, has given our company the confidence to expand our effort here significantly for 2008.

In 2207, we drilled and completed 10 horizontal James Lime wells with an average IP of about 10 million per day, and these wells have had an average 30-day production rate between 5 million and 6 million per day.

Our reserve estimates range between 2 Bcf and 5 Bcf per well, with a completed well cost of approximately $3 million. In each case, we've drilled underbalanced up to a 6000-foot lateral, and completed using the external Packers Plus production casing with up to 8 stage slick water fracs. We believe the superior results we're experiencing are due to both drilling underbalanced and getting the frac fluid off the reservoir as quickly as possible.

And we do this by having a sales line ready-to-go after the frac is completed, and we clean up through a test separator into sales. Results such the recently completed Timberstar Perry #2, which we announced last night, is flowing at 15.4 million per day, and is reflective of our completion technique.

We reported earlier that our capacity was pipeline constraint, and that a new gathering system would be in place by February. We're pleased to say that the project is completed, and the wells recently began flowing into the new system. We laid 3 new lines, a 6-inch and 12-inch gathering system, and a new 20-inch line was also laid into the field.

This upgrade is resulted in a 100 million a day of capacity available to Cabot depending on our compression and dehydration.

Since our initial discovery in the field, and with the addition of this pipeline capacity, we've grown production to about 35 million to 40 million cubic foot per day, and anticipate this rate to increase considerably through 2008.

Field now has been proven between our southernmost well, the Smith #1 and the northernmost well to-date, the Timberstar-Rusk #1, which is a distance of about 12 miles. Within this area, we have identified from 100 to 110 proven locations, with only five of those locations booked at PUD at yearend 2007. We still have another 70 to 100 potential or unproven locations on Cabot acreage in the northern part of our lease block.

We will be drilling at least 32 wells in the field in 2008. We are currently drilling with two rigs, and we'll start up a third rig and bring that along, in March. With the pipeline in place, and shortly three rigs working, we have confidence that we will be able to execute this drilling program for 2008.

With our success in County Line, we have moved to explore our James Lime knowledge base, and other areas of East Texas. We have at this time initiated two new areas, and we'll be reporting on these new areas as we put together our position, and as we drill our first well.

Now let me move a little bit to the Northwest County Line to the Trawick field. A drilling venture with Trawick field has started with great success. If you recall, this is a 36,000 acre block which Cabot found in from a major oil company. We committed to an 8 well drilling program to earn rights to the underexploited Cotton Valley in Haynesville formations under the one Tcf Trawick field. We have drilled and completed our initial earning well in the Haynesville formation, which tested at about 2.4 million per day, plus we've recognized additional behind pipe in the Cotton Valley and Travis Peak.

Our second earning well is currently drilling and will reach total depth in about three weeks. We plan to drill at least 12 wells during a staged earning process in 2008. This project exposes Cabot to not only years of drilling potential in the Cotton Valley in Haynesville but it also give us entrance to the shallower Travis Peak, James, and Petit formations.

As press release highlighted last night, we also had success on the flank of this area, and so, our adjacent Cabot acreage, with six Travis Peak wells completed, with IPs ranging between 1 million and 4 million per day. We just started drilling in Trawick, but I believe that we will be reporting our updates for years to come as we develop this field.

Now, let me move to the East. As you are aware Marcellus play developing in Appalachia is becoming one of the industry's more interesting places. This level of activity that we've seen in the competition really is unprecedented for the Appalachia basin. Traditional non-Appalachia players are kept in secure positions due to the fact that play seems to have all the elements to develop into a shale play that rivals several of the well-known shale plays, but maybe more geographically extensive.

The shale, according to literature, is approximately 50 to 300 feet big. It extents over at least two states, with reported in place reserve potential in the 100s of Bcf. Currently, the rock chemistry, the rock mechanics, shale compensation, the reservoir pressure and thermal maturation suggest this play could indeed contain reserve numbers as quoted in academy and the government.

Cabot has been active in the play for some time now. We've gathered many data points and we are actively leasing and now drilling. We have initiated six different project areas. We have acquired well over a 100,000 net acres in the play. In one of our project areas, we have drilled two vertical Marcellus wells, found a big Marcellus section, and completed each well at rates tested between 800 million to 1 million cubic foot per day. I think these rates surpassed some of those that I've heard reported in other vertical Marcellus wells.

With these results, we have begun a full-scale development program in this area that we've recently commenced. It will be a 20-well program, with our first effort of the year that we will spud by month end. Also we will see our first horizontal well spud in March.

Pipeline, permit applications and infrastructure support has begun on this project and we expect first production from this new area in the third quarter of this year. In addition to our new leasing, we've been actively evaluating currently sold in West Virginia, where we believe we've proven Marcellus. We've deepened a number of our wells to the Marcellus, and then we found through this effort that our slick water fracs are more effective stimulation than the nitrogen, and we continue to apply the slick water frac for our stimulation technique.

Most recently, Cabot drilled three vertical wells on its acreage in West Virginia and used slick water fracs with encouraging test rates of the Marcellus between 1.2 million and 1.8 million per day, at pressures considerably higher than those encountered in our typical West Virginia reservoirs. We've also recently spud our initial horizontal Marcellus test in West Virginia.

With the information gathered to-date, we've enough evidence now to suggest that the Marcellus is productive under at least 200,000 of our million acres in West Virginia. During 2008, we planned to drill most of our traditional vertical wells that we had scheduled in West Virginia down to the Marcellus and to continue to evaluate the extent of the Marcellus under existing acreage position.

The only wild card from this point forward is going to be what we'll do if the horizontal wells that we've tentatively scheduled, and one that we are currently drilling, work as we expected. If we have the success there, we will begin revamping our program to drill horizontal instead of vertical wells not only in our initial new project area that we've discussed, but also in our legacy acreage position in West Virginia.

The big positive for Cabot in West Virginia in regard to this new Marcellus initiative, is that we have a pipeline infrastructure in place capable moving the initial volumes we anticipate finding in this emerging play. Cabot along with several other companies, are very excited about the Marcellus potential. In another area I think you would miss if I didn't mention hurricane lower Herron horizontal effort in West Virginia.

Nine wells are all that we've been able to drill to-date because of the slowdown in our infrastructure issues. We do have plan 19 wells for 2008. Production is still curtailed due to the nitrogen issue, but we have received notice that the tap which was out of our control are blending our nitrogen with our gas. and the loop we have in place has been approved and will be installed next Wednesday or Thursday.

We expect to begin testing the full extent of these wells by month end. Though, we have been producing at curtail rates. We have basically had a six-month delay in moving forward with this project. So with that being said, I am pleased with our 2007 report card. I do expect 2008 production volumes to improve and I'm very excited about what we have on slate of our future opportunities and getting our 2008 program underway.

I do thank you for the support, look forward to our periodic 2008 updates.

And with that overview Holly I'll be happy to answer any questions the group might have.

Question-and-Answer Session

Operator

(Operator Instructions). Your first question comes from the line of Brian Singer, Goldman Sachs.

Brian Singer - Goldman Sachs

Thank you. Good morning.

Dan Dinges

Hey, Brian.

Brian Singer - Goldman Sachs

Can you talk about the Marcellus drilling program a bit more on your legacy acreage and why this hadn't been tested previously and the characteristics you see relative to what you're seeing, I guess, to the Northeastern some of your newly acquired acreage?

Dan Dinges

I'll turn this over to Mike for a commentary also, Bryan. But we have been deepening some of our wells up there in the Marcellus and we have established some production out of the Marcellus. But some of the deepening that we have found to-date and what we were doing was supplying our typical nitrogen fracs in some of these areas.

We are getting good data points on thickness of Marcellus and the hot shales and what not bar deepening. But the majority of what we've done so far, we've applied just our nitrogen fracs to the Marcellus section and then we come up the hole and then applied our nitrogen fracs to the other zones typical of the Appalachia area.

Most recently though we have made the effort in these three new wells we have drilled, we decided to change our technique and we applied water fracs to the wells and what we have found is that the water fracs did a significantly better job stimulating the Marcellus. And we are able to get the water back off the Marcellus formation. So that's the big change that we have seen now with our effort in the Marcellus. And I'll let Mike talk about the general characteristics of the Marcellus up there in Appalachia.

Mike Walen

Well certainly, Brian it seems like the Shale that we are finding is very extensive. It certainly has the rock chemistry and mechanical attributes that you would see in some of the more successful shale plays in the U.S.

I think one of the critical factors is that I think a lot of folks have found and I think that we discovered this through our completions in the deepening was that the Marcellus is under a different, a higher pressure regime than our typical shallow, sandstone and shale reservoirs are in the basin.

And that makes a difference in these completions and obviously we never used water on our fracs something here on shale because we can't get the water back. It appears that here in this Marcellus and West Virginia that these wells will clean up nicely and flow back that load.

Brian Singer - Goldman Sachs

Great. What were your well costs on the deepening wells?

Mike Walen

It depends on how well where we were. If you were drilling some of the deepening wells in Northwest part of West Virginia, it was really a minimal amount of money. These wells then we drilled on our legacy Creek more in the central part of West Virginia would be in the order of dry whole cost of anywhere from $350,000 to $40,000.

Brian Singer - Goldman Sachs

Okay.

Mike Walen

And that would be for vertical well Brian.

Brian Singer - Goldman Sachs

Right. You mentioned 200,000 of your million acres you think are going to be productive. Have you classified the rest as unproductive or it just hasn't yet been tested or determined?

Dan Dinges

We would still anticipate being able to prove additional Marcellus under some of our acreage. We know it's not going to be under our million acres, but we do think it's going to be a number greater than 200,000 acres.

Brian Singer - Goldman Sachs

Great. Jumping to the James Line play, you talked about your proved and unproven locations there. But I think you mentioned you've only booked a few of what you call proved locations as PUD. Could you talk about how you define proven and unproven locations under the visibility there?

Dan Dinges

Yeah, and we had that conversation after we put out the release. But basically we've drilled throughout the area where we've drilled the core of our wells that drilled in the central part of our acreage position.

But we've stepped out to the north with the Rusk well. We also have a well way south with the Smith well and between those two wells, which is where we've drilled the core of our drilling has taken place is 12 miles between those two wells, the well to the north and the well to the south.

And so we think geologically, we've seen consistency all the way throughout our acreage position in that 12-mile extent. So what I am saying basically is I feel real good about the geology in that 12-mile area. I feel real good about what we've been able to approve and around the core drilling that we have, we only booked five PUDs in our year-end booking.

And when I refer then to the 70 to 100 unproven or unproven locations, those are on our acreage that is north of the Rusk well, our northern amongst well, which we still have a sizable acreage position. So that's kind of how I differentiated proved, unproved, if you will, probably bad nomenclature.

Brian Singer - Goldman Sachs

Great, that's helpful. Thank you very much.

Dan Dinges

Yeah. You bet.

Operator

Your next question comes from the line of Nicholas Pope, JPMorgan.

Mike Walen

Good morning.

Nicholas Pope - JPMorgan

Good morning. I was hoping I could just see what your thoughts on what you all are seeing directionally with drilling costs and service costs just in your different basins. I mean just how you see things moving over the past six to seven months something like that?

Mike Walen

Okay. I'd say, back east, we are seeing some significant inflation pressures with all the activity that is now going on. Rigs are going to get tighter. I think there is a little bit of a low ride now because of the wintertime, but I think that the rigs are going to get tighter and rigs are going to go up.

I think that as if Marcellus play developed across Pennsylvania and West Virginia, you are going to see the high pressure pumping equipment which are going to be necessary to frac these wells to become into the basin. But again with the competition for services, I anticipate the rates for those services to go up too.

In east Texas regime, I think that we are seeing kind of flat median cost for rigs. In some cases, rig rates are actually going down. And then also there is a lot more equipment being brought on for the stimulations. The lot of mom-and-pop companies are smaller, frac companies coming into the business that are giving I think some at least moderation in any price increases.

On the tubular side for a while we were seeing some relatively significant reductions in tubular costs, but I noted just in the last week or two that the field plants are starting to raise rates now for tubular goods. So all in all I think that in some areas we may see a flattening of cost inflation and other areas may be a significant cost inflation.

Nicholas Pope - JPMorgan

Okay. And I guess another note, could you break out a little with the County Line wells, I know you said completed well cost of $3 million. What are the percentages of drilling versus completion? And also kind of a similar thought process and what you are seeing in the Marcellus shale and some of these first wells completion versus drilling costs?

Mike Walen

In the County Line for a typical horizontal well, our dry hole cost will run between $2 to $2.2 million something like that. And then depending on how many fracs we have in the well bore may be completion costs from $3 to $3.2 million. But our cost on these wells have been hanging in right around $3 million for all these wells that we drilled so far. And we feel confident that we will able to do maintain that cost structure.

Nicholas Pope - JPMorgan

All right. That's all I have. Thank you.

Mike Walen

Thanks, Nicholas.

Operator

Your next question comes from the line of Eric Hagen, Merrill Lynch.

Eric Hagen - Merrill Lynch

Hi. Good morning.

Mike Walen

Good morning.

Eric Hagen - Merrill Lynch

Just a follow-up on Nicholas' question on completion costs moving back to Marcellus. I think you said in Central West Virginia, there is incremental 200,000 to 400,000 to drill down to the Marcellus. How about the completion there?

Mike Walen

Well, in our vertical well, like one of our and we haven't drilled many of these in this new initiative area that we've done in West Virginia, but it looks like on a vertical sense we can get the well drill completed for anywhere from $500,000 to $800,000.

Eric Hagen - Merrill Lynch

Okay.

Dan Dinges

That's a new well. That started deepening.

Eric Hagen - Merrill Lynch

Okay, new well. Okay. Then in terms of the pressure regime you have seen between West Virginia and I am assuming the other area is in Pennsylvania. Are they similar, I mean my sense was that there were lower pressures in West Virginia, but those were pretty big flow rates, I mean in-line with what you had in the other area. Can you comment on that well, Mike?

Mike Walen

Yeah. There seem to be pods, if you will use that term of Marcellus that seem to be over pressured and Cabot is involved in some of those pods and then in West Virginia, we are seeing probably the same type of phenomena where areas where it seems like we are seeing higher pressure and then certainly in southern West Virginia the rocks that we are seeing now our normal pressure if not a little bit above normal pressure.

Eric Hagen - Merrill Lynch

Okay, great, thanks.

Mike Walen

Because of the depth involved in these wells, we are seeing considerably higher pressures than we would anticipate in our shower shale and tight sand plays.

Eric Hagen - Merrill Lynch

These are about 5000 feet or so, is that?

Mike Walen

That would be a minimum.

Eric Hagen - Merrill Lynch

Okay. And then couple more, one on Trawick, the well that you drilled there at Haynesville, do you have the cost to drill and complete that? And then what's the upside potentially from the Cotton Valley and I think it was Travis Peak. Can you commingle all those in one well bore?

Mike Walen

Well, as we said in the press release, we're in the process working with our partner and the state to get approval to co-mingle the Haynesville with the Cotton Valley. We've done that in the Mainland area and we anticipate that will be done in a relatively short order.

As far as drilling cost goes, a typical Cotton Valley well which we've modeled here if we drill it outside of the depleted units like in the Petit in the main field, we're looking at $2 million to $2.2 million are going complete a Cotton Valley well. If you go down to the Haynesville and that environment, you are going to add another $500,000 to $700,000.

Now as we drill in the middle of the field, we'll be drilling through some depleted reservoirs. We'll have to be setting here some intermediate strings to put those reservoirs behind and of course that will raise our cost up $700,000 to $800,000. And then of course it all depends on how many fracs that you put on this wells, but if you spend a $100,000 to $150,000 per frac and you put 3 to 4, 5 fracs on the wells, then all of a suddenly the cost start to increase.

Eric Hagen - Merrill Lynch

Okay, thanks. The last question was on Moxa Arch and so in that program up again any color on that, I mean I don't know what your current program is, how many rigs you have there now, how many might you add given the pricing in the Rockies? And then I guess stats on, is that already reflected in guidance or not?

Scott Schroeder

Eric, we only budgeted seven wells in our initial budget. However, you noticed the difference in the basis up there has improved considerably and Mike has instructed I guess to again ramping that program up a little bit and to move it up in the queue and we have that effort ongoing right now.

Mike Walen

And Eric that is not included in the guidance.

Eric Hagen - Merrill Lynch

Okay, great. Thanks on a great results operation. Thanks again.

Mike Walen

Thanks, Eric.

Operator

Your next question comes from the line of David Adams, Jefferies and Co.

David Adams - Jefferies and Co.

Hi, guys.

Dan Dinges

Hi, David, how are you?

David Adams - Jefferies and Co.

Good. A couple of more questions on the Marcellus well costs for their existing acreage. So I understand to drilling too deep in a well and including completion cost, it's $350,000 to $400,000 and then for a new well to drilling completed, it's 500 to 800, is that how I understand it?

Mike Walen

Yeah. That would be actually if you went in some of our -- if we had an older Herron test that we would keep deep on that, you can probably deep it into the Marcellus for less and complete it for less than $250,000. If you are drilling down from the wear, let say or from the big line then you're going to be looking at that larger number and we feel pretty confident by drilling new well, you could drill and complete for that $500,000 to $800,000 depending on that where you are in the state.

David Adams - Jefferies and Co.

Okay. And can you kind of give us the sense of inventory of the number of wells that you could just deep in versus new wells on your acreage position?

Mike Walen

Well that would be a question of economics, obviously if the current well is making good economic gas rate, production rates, we would not be probably willing to just shut that production off and then deepen.

But I think one thing we are looking at David is the fact that we've already got the location pads already in place in all of these wells. We can certainly go in and twin each one of those wells down to the Marcellus. We think the economics would obviously support that and by doing that, that would save a lot of money on road and location construction, pipeline construction, surface facilities, and I think that well might be one route that we could go down.

David Adams - Jefferies and Co.

Alight, absolutely. And what are your expectations for a horizontal test cost?

Mike Walen

Well, as Dan said, we spudded our first horizontal well in this area. We are going to handle that well as we speak with our experience in hurricane. We think that we are going to be able to do exactly that same type of well board and hopefully we'll be able to get cost down to about that $1 million a well for a horizontal drilling complete, that would be our goal.

David Adams - Jefferies and Co.

Okay.

Dan Dinges

And certainly, we would be seeing multiples on our production rate and the EUR is going to be still a number that's a best guess at this stage.

David Adams - Jefferies and Co.

Great, okay. And economic looks unbelievable. Back to Trawick, is there anything you saw on the well logs that would be easy to believe that the Cotton Valley is not going to work out?

Mike Walen

Not really, we have an awful lot experience looking at Cotton Valley through our Minden program, this stuff is just a little bit further south of there, the logs has the same characteristics, multiple stack sands, 10, 20,30 foot thick. Not real porous, 8% to 10% porosity. It does not look to be any different than the Cotton Valley and we think that we are up and top of the hill here. We are going to have really good success complete in Cotton Valley as well as Travis Peak.

David Adams - Jefferies and Co.

Okay. And then one other Marcellus question, back to your acres in St. Louisiana. Are well costs similar there as well for the deeper in one area versus the other?

Mike Walen

I would say that they are within range of each other. Obviously, it depends on the depth that they are drilling and how long any horizontal legs might be and how may fracs that you might on the well.

David Adams - Jefferies and Co.

Right. Okay. Great, guys. This is exciting. Thank you.

Mike Walen

Thanks.

Operator

Your next question comes from the line of Ray Deacon, BMO Capital Markets.

Ray Deacon - BMO Capital Markets

Hey, Mike, I had a question about the 20 wells you are going to be drill in the Marcellus, is the bulk of that going to be in kind of your legacy area or will that be split between northern and central West Virginia? And you talked about basins or the shale being between 15 and 300 feet thick. I was wondering if it, does it appear that the thickness and the quality of the wells are co-related or is there some other factor that influences it?

Dan Dinges

Yes, Ray, this is Dan. I will take the first part of that and latter over to Mike on the thickness and what not. But our 20 well program is on a new list initiative in Pennsylvania.

Ray Deacon - BMO Capital Markets

Okay.

Dan Dinges

That we have put together. So that is a brand new area for us and that's why we've mentioned laying the infrastructure in there and what are estimated time of first productions going to be, but we're as we speak going to be. We drilled two wells in there and we're moving forward on the third well, with the fourth well in this little project area going to be horizontal. I'll let Mike address the thicknesses.

Mike Walen

Yeah, that thickness references really comes from the research we've done in the literature. We haven't talked about how thick our wells are, but if you look in some of the stuff that’s published both by government agencies and the universities, you can readily see the Marcellus has a strong trend through the two stages and that the thickness, actually feathers out to the West. We just use that kind of 50 foot cutoff and we're up to the 300 foot that we saw on this published maps.

Ray Deacon - BMO Capital Markets

Okay, good. And I guess just one more on the -- I'm not sure I fully understood your comment from the paradoxes, do you think you may take a partner in some of the deeper wells so there maybe some capital added later this year, or I guess what's the plan over the next couple of quarters?

Dan Dinges

Yeah. Paradox we’re not able to drill yet and won't be able to move a rig in the paradox until about May or June. But in the Moxa is where we’re taking about ramping up our program, we've that 80 acre down space project going on in the Moxa and we're not talking about taking partners on a ramp up program there. And though we’re adding some wells there, we are not changing our guidance at this time on our capital program.

Ray Deacon - BMO Capital Markets

Okay, great. And just maybe, I know you talked about having some shut in production in the fourth quarter due to lower prices in October. How much production would you expect to gain back in the first quarter as the results are turning some of those volumes back online?

Dan Dinges

Well, our rate has been affected because of the superior weather still that that's a Rocky Mountain is seeing. We've had a number of areas that a well or area, wells will go down that we -- there is so much snow and what not on a road until we can get cash in there, plow the road, we can't get our guys to the wells or to the facilities to get back on. So we are still being affected by weather up there right now. But on a snapshot rate of where we are, like yesterday, we were at like 252 million day but there is all kinds of movement going on because of the weather.

Ray Deacon - BMO Capital Markets

Got it. Thanks very much.

Dan Dinges

Okay, thank you.

Operator

Your next question comes from the line of Jack Aydin, KeyBanc Capital Markets.

Jack Aydin - KeyBanc Capital Markets

Hi, Dan, hi everybody.

Dan Dinges

Hi Jack, how are you?

Jack Aydin - KeyBanc Capital Markets

Good. Dan, you mentioned that you booked only 5 parts from the County Line, could you give me indication what the total was? That's a loaded question by the way.

Dan Dinges

What the total..?

Jack Aydin - KeyBanc Capital Markets

You booked for those five PUDs?

Dan Dinges

In reserves, what?

Jack Aydin - KeyBanc Capital Markets

Yes.

Dan Dinges

What we booked per PUD?

Jack Aydin - KeyBanc Capital Markets

Yes.

Dan Dinges

We assigned right at or may be slightly over 3 Bcf a PUD.

Jack Aydin - KeyBanc Capital Markets

Okay. So, with the 30-day average of those 12 wells running at about 5.7 million a day and using 2 to 5, I assume that low end is too conservative, isn't it Mike?

Mike Walen

Jack, we like to deliver on what we say, so we are not going to jump out there and say big numbers.

Jack Aydin - KeyBanc Capital Markets

Okay. Next question on Marcellus, Dan what will make you -- at what point you might decide, you have enough of piloting and instead of drilling vertical well you go full-fledged horizontal?

Dan Dinges

Jack, I would think that's going to be determined fairly quickly. Our first horizontal well and Marcellus is being drilled as we speak. That particular well is in West Virginia. We do have plans to drill the next well in our new area in Pennsylvania a horizontal.

We are doing things behind the scenes right now to amend our program from a predominant vertical to a horizontal effort. And you have to remember that up in the East things are little bit different from the standpoint, there has not been a whole lot of horizontal drilling in the East.

So, putting together the units, getting ahead of a horizontal drilling program, doing all the things that you need to do from a front-end standpoint or permitting and applications in all is a little bit of a new venture in the East. And however with that being said, we have started their process. So I can't sit comfortably and say how quick we can move with the horizontal program until I get a feel on how we can put all these things on the front end together and we are doing that right now.

Jack Aydin - KeyBanc Capital Markets

Okay. Do you have the people to carry the program in Appalachia the way you want or you are constraint by the people availability?

Dan Dinges

Yeah, that's a good question, Jack. We certainly have seen, our people have received phone calls, they have been asked to join other companies out there that are trying to get in to their area and get their staffs put together. We feel fortunate that we have not lost, only but a couple of employees. We have our Board meeting coming up on the 19th and 20th which will address the compensation issues.

We just implemented a supplemental employee incentive program that is available now to all employees that are not officers of the company and that program will allow the group with success that's aligned with the shareholder if we achieve a $50 stock price, they will get a bonus recognition and that has to be for 20 trading days over a period of time. They will get recognition for with an additional 20% of their salary and if we achieve a $60 stock price within a prescribed period of time under this plan, the employees have the opportunity to receive a bonus of 50%, up to a 100% of their salary.

And what that means is, folks are focused, they know what it takes because I'll go around and explain them what it's going to take to ramp up the Cabot's value and share value to the shareholder. They will understand it. And money certainly focuses a lot of people and I don't envision that this program is going to be any exception to that. We're excited about it and the feedback that I've got has been very good.

So we do plan on hiring some additional people. I think this program will allow us to not only retain, but I think it will allow us now to attract some good people to implement this program.

With that being said, a little big long-winded Jack, but with that being said the program we've in front of us that we've designed for the East which is the largest program that we never tried to tackle. I think we can accomplish with our existing staff if we do amend our program and we decide that maybe we need to allocate our additional capital or increase our capital program and it goes to the East. I think we can ramp up a little bit with our existing staff, but I think we'll also need some key employee hours to accomplish that.

Jack Aydin - KeyBanc Capital Markets

And the hurricane project, did you tap into their pipeline already?

Mike Walen

No, it will be done Wednesday or Thursday, that has been kind of like watching paint dry.

Jack Aydin - KeyBanc Capital Markets

Okay. So how much did those cost us during the fourth quarter lack of that production, Mike do you have an idea?

Mike Walen

That's a tough question. So I don't now how the well is going to behave. We had forecasted that we get 1 million to 2 million a day production out of those wells just from those first few wells. And of course, we didn't see that. So it had a pretty material impact.

And then of course, Jack, we also had some -- we will have slow and give some of our pipeline late to the wells and we have a number of wells that need to be hooked up out in this traditional area.

Jack Aydin - KeyBanc Capital Markets

Okay.

Dan Dinges

And might add we did not continue drilling in hurricane because of this nitrogen issue. So that's slowed us down a little bit too.

Jack Aydin - KeyBanc Capital Markets

Thanks a lot.

Dan Dinges

Okay, Jack. Thanks.

Operator

You have a follow-up from the line of Nicholas Pope, JPMorgan..

Nicholas Pope - JPMorgan

Hello again. I was hoping if you can just briefly hit on, I guess you mentioned earlier the infrastructure that is going to be needed in the Marcellus shale, some of the midstream items, gathering lines, processing plants. Could you discuss where we are now and where we all think we need to go to really meet capacity that's coming online?

Dan Dinges

Well, we have and I will turn this over of to Jeff, our VP of Marketing and he can go into the details, but we are fairly close to a larger interstate land and what our application and all and expansion process is and Bob's tapping into that and expanding up into our existing lease hold division. I'll let Jeff kind of fill in some of the details.

Jeff Hutton

Yes. Our new play, it's more of a matter laying the basic trunk lines and the flow lines to new well locations. We do have a major interstate pipeline running through our lease hold that we have access to which has from a physical standpoint plenty of capacity and what's for January, we have existing infrastructure, it's just a matter of adding compression where we see leaks and also laying the physical flow lines to new wells.

Typically this gas is pipeline quality gas. It does not require a processing per se. It will require some hydrocarbon dewpoint control and water control. But other than that there is no restrictions on that and need of having to build the processing plant.

Nicholas Pope - JPMorgan

That's all I had. Thanks, Jeff.

Jeff Hutton

Right, thanks, Nicholas.

Operator

Your next question comes from the line of [Kevin Claire], Bear Stearns.

Kevin Claire - Bear Stearns

Good morning. I've got just a couple of quick ones and you basically were in a kind of hit on the infrastructure question that I was going to ask. But are there any right of way used with respect to the infrastructure and the Marcellus referred other companies say that that could be problematic?

And then second is any of your Marcellus acreage, does that need to be held by production?

Dan Dinges

Well, first off, the right way the question is, it'll probably depend on when you heard it from other, probably depend on how close they are to communities and how densely populated it might be or if they have, their interconnect has to go through a town or something like that. But we're not seeing in the area that we have right now concerned with right of way issues.

Kevin Claire - Bear Stearns

Okay.

Dan Dinges

And the follow-up question.

Kevin Claire - Bear Stearns

On your Marcellus acreage, does any of that need to be held by production?

Dan Dinges

Well, we have leased in the new areas, we have multi-year lease terms. So all of that will have to be drilled and developed pursuing to the lease terms. But we have years to be able to that. On our existing Legacy acres over million acres, all of that is HBP.

Kevin Claire - Bear Stearns

Okay, great. Thank you.

Operator

At this time, there are no further questions.

Dan Dinges

Great, Holly, I appreciate everybody's interest. Certainly, you can see by the questioning as we have been receiving in the last few months directed towards the East Texas and the Marcellas. Our focus program for 2008 is in those areas. We are looking at what we might be able to in expanding our programs in each of these areas, and certainly look forward to reporting back to up at the end of next quarter. Thank you very much.

Operator

Thank you for participating in today's Cabot Oil & Gas conference call. You may now disconnect.

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Source: Cabot Oil & Gas Corp. Q4 2007 Earnings Call Transcript
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