Coterra Energy Inc (CTRA) 2007 Q4 法說會逐字稿

Good morning, I am Holly. I will be your conference operator today. I would like to welcome everyone to Cabot Oil and Gas 2007 fourth quarter 2007 conference call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question-and-answer session. (OPERATOR INSTRUCTIONS)

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

Thank you, Holly. We appreciate you joining us for Cabot's year end teleconference call. As usual, I have with me today to answer any questions you might have 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 Controller. Before we start, let me say that the statements regarding forward-looking information included in the press releases apply to my comments today. As you are all 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 the program and the ability to create value for the shareholder. I feel one of the vital measures of value creation is the company's ability 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 proved 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 proved reserve breakdown at year-end was 48% in the east, 30% in the west, 20% Gulf Coast, and 2% in Canada. As some of you know, Cabot has a deep inventory of opportunities with the estimated 10,000 plus locations and over 5 TCFE of underrisked resource potential, which by the way does not include any of the Marcellus potential that we have and 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 are pleased to achieve that goal with an all in finding cost of $2.07 per Mcfe. I believe that when all the reports for the year are in, Cabot's organic 334% reserve replacement at around $2 all in finding cost 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 on the numbers in 2008.

In regard to production, as we indicate 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 production, our pro forma 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 we have had in the east in our hurricane project, and some of the slow well connects we have experienced 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 a $1.67 per share after you move a small impairment in gain on sell activity. This level of net income was Cabot's second highest for any full year period and exceeded only by last year's effort. Related pricing from hedging, Cabot experienced a $0.99 per Mcf pick up 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 the website. And for 2008, we are now approximately 50% hedged with an average floor or swap price of $1.19 (sic) per Mcf. Excuse me. I like to transpose that. $8.19 per Mcf. We have also initiated a position in 2009 with six collared contracts. Four of the six are in the west region where we have highest basis but we are still realizing a floor averaging $7.98 per Mcf. All our 2009 hedges are at the specific sales point for gas and does include our basis. And these 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 periods, offset by lower expiration as we focused strategically on the expiration and lower stock compensation.

And 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 Appalachian. And within these two areas, it encompasses a couple of the hottest plays in the industry today. Cabot will allocate over 80% of our capital to these two areas and with many of your questions in the last few months being directed to east Texas and Appalachia, I will spend most of the operation discussions in these areas. However, though we are heavily focused in these two areas, I do want to mention the mid continent area does add value to the successful development program in the Morrow and Chester, including the largest program in the 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 our 2008 program. Additionally, our Canadian effort will remain small at this time, focused mainly on Hinton and Musreau. Now moving to East Texas, the County Line project has become a premier development project in the company. The consistent production growth, nice reserve additions, and an excellent return on capital in the horizontal [James Line] that County Line has given our company the confidence to expand the effort here significantly for 2008. In 2007, we drilled and completed 10 horizontal James Line 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 and 5 Bcf per well with a completed well cost of approximately $3 million. In each case, we have drilled, under balanced up to a 6,000-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 are experiencing are due to drilling under balanced and getting the frac fluid off the reservoir as quickly as possible. We do this by having the sales line ready to go after the frac is completed and we clean up through a test separator into the sales. Results such as the recently completed Timberstar Perry #2 which we announced last night flowing at 15.4 million per day is reflective of the completion technique.

We reported earlier that our capacity was pipeline constraint and that a new gathering system would be in place by February. We are pleased to say that the project is completed and the wells recently began flowing into the new system. We laid three new lines, a 6-inch and 12-inch gathering system, and a new 20-inch line was also laid into the field. This upgrade has resulted in 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 have grown production to about 35 million to 40 million cubic foot per day and anticipate this rate to increase considerably through 2008. The 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 between 100 to 110 proven locations, with only five of those locations booked at PUDs at year end 2007 and 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. And we are currently drilling with two rigs and we will start up a third rig in March. And 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 exploit our James Line of knowledge base in other areas of east Texas. And we have at this time initiated two new areas and we will be reporting on these new areas as we put together the position and drill the first wells.

Now, let me move a little bit to the northwest of County Line to the Trawick Field. Our drilling venture at Trawick Field has started with great success. If you recall, this is a 36,000-acre block which Cabot farmed in from a major oil company. We committed to a eight well drilling program to earn the rights to the underexploited Cotton Valley and Hainesville formations under the 1 TCF Trawick Field. We have drilled and completed our initial earning well in the Hainesville formation which tested at 2.4 million per day, plus we recognized additional behind pipe in the Cotton Valley and Travis Peak. And 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 the staged earning process in 2008. This project exposes Cabot to not only years of drilling potential in the Cotton Valley in Hainesville, but also gives us entrance to the shallower Travis Peak, James and Pettit formations. As the press release highlighted last night, we have also had success on the flank of this area and some of our adjacent Cabot acreage, with the six Travis Peak wells completed with IPs ranging between 1 million and 4 million per day. We just started drilling in Trawick, and I believe we will be reporting the updates for years to come as we develop this field.

Now, let me move to the east. As you are aware, the Marcellus developing in Appalachian is becoming one of the industry's most interesting plays. And this level of actively that we have seen and the competition really is unprecedented for the Appalachian basin. Traditional nonAppalachian players are attempting to secure positions due to the fact that the play seems to have all the elements to develop into a shale play that rivals some of the well known shale plays and may be more geographically extensive. The shale is according to the literature approximately 50 feet to 300 feet thick. It extends over at least two states with reported in place reserve of potential in the hundreds of PCF. Currently the rock chemistry, the rock mechanics, shale composition, the reservoir pressure and thermal maturation suggests this play could indeed contain reserve numbers as quoted in academia and in the government. Cabot has been active in the play for some time now. We have gathered data points and we are actively leasing and drilling. We have initiated six different project areas and acquired well over 100,000 net acres in the play. In one of our project areas, we have drilled two vertical Marcellus wells and found a thick Marcellus section and completed each well at rates tested between 800,000 to 1 million cubic foot per day. I think these rates surpass some of those that I heard reported in other vertical Marcellus wells.

And with these results, we have began a full scale development program in this area that we have recently commenced. And it will be a 20 well program. With our first effort of the year that we will spud by year-end and we will see -- by month end, excuse me. And also, we will see our first horizontal well spud in March. Pipeline permit applications and infrastructure support has begun on the project and we expect first productions from the new area in the third quarter of this year.

And in addition to our new leasing, we have been actively evaluating currently sold in West Virginia, where we believe we have proven Marcellus. And we have deepened a number of our wells to the Marcellus and 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 the 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 the typical West Virginia reservoirs. We have also recently spud our initial horizontal Marcellus test in West Virginia.

With the information gathered to date, we have enough evidence to suggest that the Marcellus is productive under at least 200,000 of our 1 million acres in West Virginia. And 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 the existing acreage position. And the only wild card from this point forward is going to be what we will do if the horizontal wells that we have tentatively scheduled and one we are currently drilling work as we expected. If we have the success there, we will begin revamping the program to drill horizontal instead of vertical wells, not only in the initial new project area that we have discussed but also in the 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 of moving the initial volumes we anticipate finding in this emerging play. And Cabot along with several other companies are very excited about the Marcellus potential.

And in another area, I would be remiss if I didn't mention Hurricane, our Lower Huron horizontal effort in West Virginia. And nine wells are all we have been able to drill to date because of of the slowdown in our infrastructure issues. We do have planned 19 wells for 2008. And production is still curtailed due to the nitrogen issue, but we have received notice that the tap, which was out of our control, 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 the wells by month end, though we have been producing at curtailed rates. We have basically had a six month delay in moving forward with this project.

With that being said, I am pleased with the 2007 report card. I do expect 2008 production volumes to improve and I am 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. I look forward to our periodic 2008 updates, and with that overview, Holly, I will be happy to answer any questions the group might have.

(OPERATOR INSTRUCTIONS) First call is from Brian Singer of Goldman Sachs.

Good morning. 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 are seeing to the north and east in your newly acquired acreage?

Yes. I will turn this over to Mike for commentary also, Brian. And 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 applying our typical nitrogen fracs in some of these areas and getting good data points on thickness of Marcellus and the hot shales and whatnot by deepening, and the majority of that we have done so far -- we have applied just our nitrogen fracs to the Marcellus section and we have come up the whole and applied the nitrogen fracs to the other zones typical to the Appalachian area. Most recently though we have made the effort in these three new wells we have drilled. We decided to change the technique and we applied water fracs to the wells and what we had found is the water fracs did a significantly better job stimulating the Marcellus and were 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 will let Mike talk about the general characteristics of the Marcellus up there in Appalachian.

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. And I think one of the critical factors that a lot of folks have found and we discovered this through our completions in the deepenings was that the Marcellus is under a different, higher pressure regime than what our typical shallow sandstone and shale reservoirs are in the basin. That makes a big difference in these completions and obviously we never used water on our fracs up in the Huron Shale because we can't get the water back. It appears that here in this Marcellus in West Virginia, these wells will clean up nicely and flow back that load.

Great, what were your well costs on the deepening wells?

Those -- it depends on where we were. If we were drilling some of the deepening wells in the northwest part of West Virginia, it was really a minimal amount of money. And these wells we drilled on the legacy increase more in the central part of West Virginia would be in the order of a dry hole cost of anywhere from $350,000 to $400,000.

Okay.

And that would be for vertical well ,

Right. You mentioned 200,000 of your 1 million you think are going to be productive. Have you classified the rest as unproductive or it isn't yet tested or determined?

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

Jumping to the James Line play, you talked about the proved and unproven locations there. You mentioned you booked a few of what you call prove locations as PUDs. Could you talk about how you define proven and unproven locations and the visibility there?

Yes, we had the conversation after we put out the release. But basically, we have drilled throughout the area where we have drilled a core, the core of our wells that have been drilled in the central part of our acreage position but we have stepped out to the north. With the Rusk well and we also have a well way south with the Smith well and between those two wells which is where we drill -- the core of the drilling is taking place is 12 miles between those two wells, the well to the north and well to the south. So we think geologically we have seen consistency through the acreage position in the 12 mile extent. And so what I am saying basically, I feel real good about the geology in the 12 mile area. I feel real good about what we have been able to prove 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 undrilled locations -- not undrilled, but unproven locations -- those are on our acreage that is north of the Rusk well, our northernmost well, which still we have a sizeable acreage position. That's how I am differentiating proved, unproved if you will. Probably bad nomenclature.

That is helpful. Thank you.

You bet.

Your next line comes from Nicholas Pope, JPMorgan.

Good morning. I was hoping I could hear your thought on what are you seeing directionally with drilling costs and service costs in the different basins and how you have seen things moving over the past, six, seven months, something like that.

I would 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 bit of a lull right now because of the wintertime. And I think that the rigs will get tighter and rates are going to go up. I think that as this Marcellus plays develops across Pennsylvania and West Virginia, you will see the high pressure pumping equipment which is necessary to crack these wells to be coming into the basin, but again with the competition for services, I anticipate the rates for those services to go up too. And in the east Texas regime, we, I think that we are seeing kind of a flat median cost for rigs and in some cases rig rates are going down. And then also, a lot more equipment being brought on for the stimulation and a lot of mom and pop companies and smaller frac companies coming into the business that are giving some 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 in the last week or two, the field class is starting to raise rates now for tubular goods. And all in all, in some areas we may see a flattening of cost inflation and other areas maybe significant cost inflation.

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

And in the County Line for a typical horizontal well, our dry hole cost would be between $2 million to $2.2 million. Something like that. And depending on how many fracs we have in the well bore and maybe a completion cost from $3 million to $3.2 million, and our cost on the wells have been hanging right around $3 million for all these wells that we drilled so far. And we feel confident that we are going to maintain that cost structure.

All right. That's all I have, thank you.

Thanks, Nicholas.

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

Good morning. Just to follow up on Nicholas' question on completion costs of moving back to the Marcellus. You said in West Virginia, central West Virginia, it is incremental $200,000 to $400,000 to drill down to the Marcellus. How about the completion there?

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

Okay.

That's a new well.

That's a new well. Not a deepening.

New well. Okay. And then in terms of the pressure regime you have seen between West Virginia and I'm assuming the other areas in Pennsylvania. Are they similar? And my sense is that, they were lower pressures in West Virginia but those were pretty big flow rates and in line with what you had in the other area. Can you comment on that at all, Mike?

Yes, there seems to be pods, if you will, to use that term of Marcellus, they seem to be overpressured. And Cabot is involved in some of the pods and then in West Virginia, we are seeing probably the same type of phenomena where it seems like we are seeing higher pressure and certainly in southern West Virginia, the rocks that we are seeing now, are normal pressured. If not a little bit above normal pressured. It comes off the depth in these wells. And we are seeing considerably higher pressures than we would anticipate in the shallower shale and tight sand plays.

This is 5,000 feet or so?

That would be a minimum depth.

Okay. Then a couple more. On Trawick, the well you drilled there, the Hainesville, do you have the cost of drilling to complete that? And what is the upside from the Cotton Valley and I think it was Travis Peak and can you commingle those in one wellbore?

As we said in the press release, we are in the process of working with our partner and the state to get approval to commingle the Hainesville with the Cotton Valley. We have done that in the Minden area and that will be done in a relatively short order. As far as drawing cost goes, a typical Cotton Valley well, which we have modeled here. If we drill it outside of the depleted units like in the Pettit in the main field. We are looking $2 million to $2.2 million of drilling to complete a Cotton Valley well and if you go down to Hainesville and that environment, you will add $500,000 to $700,000. Now as we drill in the middle of the field, we will be drilling through some of the depleted reservoirs and we have to be setting (inaudible) in the intermediate strings and to put those reservoirs behind and that will raise the costs up to $700,000 to $800,000. And it all depends on how many fracs you put on the wells and if you expand to $150,000 per frac and put the 3 to 4 to 5 fracs on the well, then the costs start to increase.

Thanks. Last one was on Moxa Arch, and starting that program up again. Any color on that? I don't know what the current program is. How many rigs you have there now, how many might you add given the better pricing in the Rockies and I guess, if Scott is on, is that reflected in the guidance or not?

Yes, Eric, we have, we only budgeted seven wells in our initial budget. However, you notice the difference in the basis up there. Has improved considerably and Mike has instructed the guys 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.

That is not included in the guidance.

Thanks and great results operationally.

Thanks, Eric.

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

How are you?

Good. A couple more questions on the Marcellus well costs for existing acreage. So I understand to drill and deepen a well, and including completion costs, it is $350,000 to $400,000 and then for a new well to drill and complete, it is $500,000 to $800,000. Is that how I understand it?

That would be actually, if you went in some of our if we had an older Huron chest that we could deepen on that. You could probably deepen into the Marcellus for less -- and complete it for less than $250,000. If you are drilling down from the weir, or from the big line, then you are looking at the larger number. And we feel pretty confident by drilling a new well, you could drill and complete for the $500,000 to $800,000 depending on where you are in the state.

And kind of give us a sense of inventory of the number of wells you could deepen versus new wells on the acreage position?

That would be a question of economics. And obviously if the current well is making good economic gas rate, production rates, we would not be willing to shut the production off and then deepen. But I think one thing that we are looking at, David, is the fact that we have already got the location pads in place in all of these wells and we can certainly go in and twin each one of those wells down to the Marcellus. We think the economics will support that. And by doing that, that will save a lot of money on road and location construction, pipeline construction, and surface facilities. And that will be one route we could go down.

Absolutely. What are your expectations for a horizontal test cost?

Like Dan said, we spudded our the first horizontal well in the area. We are drilling ahead on that well as we speak. With the experience in Hurricane, we think that we are going to be able to do exactly that same type of well bore. And hopefully get cost down to about that about that $1 million of well for a horizontal.

Drill and complete.

That will be our goal.

Okay.

Certainly we would anticipate seeing multiples on the production rate. And the EUR is going to be a number that is a best guess at this stage.

Okay. Great. Economics looks unbelievable. Back on Trawick, is there anything you saw in the well logs that would lead you to believe the Cotton Valley is not going to work out?

Not really. We have a lot of experience looking at Cotton Valley through our Minden program and just up little farther south of there. The logs have the same characteristics. Multiple stacks sands and 10 to 20 to 30-foot thick. Not real porous, 8 to 10% porosity. And it does not look to be any different than the Cotton Valley. And we think when we are up top the hill here, we will have good success completing Cotton Valley as well as Travis peak.

Then one other Marcellus question. Back to your acreage in Pennsylvania. Are well costs similar there as well or cheaper in one area than the other?

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

Thanks, guys, this is exciting.

Thanks.

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

Mike, I had a question about the 20 well program you are drilling in the Marcellus. Is the bulk of that in your legacy area or will that be split between northern and central West Virginia? And you talked about the shale being between 50 feet and 300 feet thick. I was wondering -- does it appear the thickness and the quality of the wells are correlated or is there some other factor that influences it?

This is Dan. I will take first part of that and lateral over to Mike on the thickness and whatnot. Our 20 well program is on a new leased initiative in Pennsylvania.

Okay.

That we have put together. So, that is a brand new area for us and that's why we mentioned laying the infrastructure in there and what our estimated time of first production is going to be. But we are, 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. And I will let Mike address the thicknesses.

Yes, we, that thickness reference comes from the research we have done in the literature. And we haven't talked about how thick our wells are, but if you look in some of this stuff that is published both by government agencies and the universities, you can readily see that the Marcellus has a strong trend through the two states and the thickness -- it feathers out to the west. We used kind of a 50-foot cut off and went up to the 300-foot that we saw on the published maps.

Okay. And I guess just one more. I am not sure if I fully understand your comment on the Paradox. Do you think you may take a partner in some of the deeper wells and there may be capital added later this year and what is the plan over the next couple of quarters?

Yes. Paradox, we are in a, we are not able to drill yet and won't be able to move the rig in Paradox until May or June.

Okay.

But in the Moxa, is where we are talking about ramping up our program. We have that 80-acre downspace project going on in the Moxa. And we are not talking about taking partners on a ramp up program there. And though we are adding some wells there, we are not changing our guidance this time on the capital program.

Great. And just maybe, I know you talked about having some shut in production in the fourth quarter due to low prices in October. How much production would you expect to gain back in the first quarter? As a result of turning some of those volumes back online.

And well, we are -- our rate has been affected because of the severe weather still that the Rocky Mountains is seeing. We had a number of areas that a well or area of wells will go down. And there is so much snow and whatnot on the roads. Until we can get cats in there to plow the roads, we can't get the 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 a day. But there is all kinds of movement going on because of the weather.

Got it. Thanks very much.

Okay. Thank you.

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

You booked only five PUDs from the County Line. Could you give me an indication what the total was? That is a loaded question by the way.

What the total?

You booked for those five PUDs.

In reserves?

Yes.

Well -- per PUD?

Yes.

Well, we assigned right at or maybe slightly over 3 Bcf of PUD.

And with 30 day average over those 12 wells running at 5.7 million a day. And using 2 to 5 Bs. I assume the lower end is too conservative, isn't it, Mike?

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

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

Jack, I would think that is going to be determined fairly quickly. And our first horizontal well in the Marcellus is being drilled as we speak. That particular well is in West Virginia. And we do have a plans to drill the next well in our new area in Pennsylvania horizontal. And we are doing things behind the scenes right now. To amend our program from the predominant vertical to a horizontal effort. You have to remember that up in the East, things are a little more different from the standpoint -- there has a not a local of horizontal drilling in the east, so putting together the units, getting ahead of a horizontal drilling program, doing all the things you need to do ona front end standpoint of permitting and applications and all. It is a little bit of a new venture in the east. And however, with that being said, we have started that process. I can't sit comfortably and say how quick we can move with the horizontal program until I get a feel on how to put all these things on the front end together. We are doing it right now.

Do you have the people to carry the program in Appalachia, the way you want? Or you are constrained by the people's availability?

Good question, Jack. We have certainly seen our people have received phone calls. And they have been asked to join other companies up there that are trying to get into the area and get their staffs put together. We feel fortunate we have not lost but a couple of employees. And we have our board meeting coming up on the 19th and 20th which will address 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 is 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 with an additional 20% of their salary much and if we achieve a $60 stock prize within a prescribed period of time under the plan, the employees have the opportunity to receive a bonus of 50%, up to 100% of their salary, and what that means is that folks are focused and know what it takes. Because I will go around and explain to them what it is going to take to ramp up Cabot's value and show value to the shareholder and they will understand it.

And money focuses a lot of people and I don't envision that this program is going to be any exception to that. We are excited about it and the feedback has been very good. And so, we do plan on hiring some additional people and I think this program will allow us not only to retain but allow us now to attract some good people to [temperament] this program. With that being said -- a little long-winded, Jack. But with that being said, the program we have in front of us that we designed for the east which is the longest program we ever 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 the capital program and it goes to the east. We can ramp up a little bit with our existing staff, but I think we will also need some key employee hires to accomplish that.

Okay. Is the Hurricane project -- did you tap in the pipeline -- tap into the pipeline already?

No. It will be done Wednesday or Thursday. That has been kind of like watching paint dry.

Okay. How much did it cost us during the first quarter. Lack of the production. Mike, do you have an idea?

That's a tough question. Because I don't know how the world is going to behave. We had forecasted we would get 1 million to 2 million a day of production a day from the wells just from the first few wells and of course, we didn't see that. And it had a pretty material impact and then of course, Jack, we had some, we were kind of slow in getting some of the pipelines late to the wells and we had a number of wells that needed to be hooked up. Out in the traditional area.

Okay.

We did not continue drilling in Hurricane because of this nitrogen issue. That slowed us down a little bit too.

Thanks a lot.

Thank you.

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

I was hoping you could hit on -- I guess you mentioned earlier the infrastructure that was going to be needed in the Marcellus shale, some of the midstream items -- gathering lines, and processing plants and could you discuss I guess where we are now? And where you all think we need to go to meet the capacity that is coming online?

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 large interstate line and what our application and all and expansion process is, it involves tapping into that and expanding up into our existing leasehold position and I will let Jeff fill in the details.

Yes. Our new play, it is more of laying the basic trunk lines and the low lines to new well locations. And we do have a major interstate pipeline running through the leasehold that we have access to, which has from a physical standpoint plenty of capacity. And in West Virginia, we have existing infrastructure and it is just a matter of adding compression where we see needs and also, laying the typical flow lines to the new wells. Typically this gas is pipeline quality gas and does not require processing per se. And it will require some hydrocarbon dewpoint control and water control. But other than that, no restrictions on a need of having to do a processing plant.

That's all I had. Thanks again.

Thanks, Nicholas.

Your next question comes from the line of Kevin Klare, Bear Stearns.

I have a couple of quick ones and you hit on the infrastructure question I was going to ask. Are there any right of ways used with respect to the infrastructure in the Marcellus? We heard other companies say it could be problematic. Second, is any of that Marcellus acreage -- does that need to be held by production?

Well, first off, the right of way question is, it will probably depend on when you are hearing on it from other companies. 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. We are not seeing in the area that we have right now concern with right of way issues.

Okay.

And the follow up question?

Just on your Marcellus acreage -- does any of that need to be held by production?

We have leased, in the new areas, we have multi year lease terms. And so, all of that will have to be drilled and developed pursuant to the lease terms. But we have years to be able to do that. On our existing legacy acreage over 1 million acres, all of that is HBP, held by production.

Great, thank you.

At this time there are no further questions.

Great, Holly. Appreciate everybody's interest. And certainly, can you see by the questioning as we have been receiving in the last few months directed towards east Texas and the Marcellus, our focused program for 2008 is in those areas. And we are looking at what we might be able to do. And in expanding our programs in each of the areas and certainly look forward to reporting back to you at the end of next quarter. Thank you very much.

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