Coterra Energy Inc (CTRA) 2011 Q3 法說會逐字稿

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 and Gas Quarter 3, 2011 conference call. All lines have been placed on mute to prevent any background noise. After the speakers remarks there will be a question and answer session.

(Operator Instructions)

I would now like to turn today's call over to Dan Dinges, Chairman, President and CEO.

Thank you, Holly. I appreciate everybody joining us this morning. I have in the room with me today Scott Schroeder; Jeff Hutton, our VP of Marketing; Steve Lindeman, our VP of Engineering; Matt Reid, our VP of the South Region; and Phil Stalnaker, our VP of our North Region. Let me just make an opening comment that the forward-looking statements included in the press release do apply to my comments today.

At this time, we have many things to cover and I will also try to expand on the press releases that were issued last night. I will briefly cover the third quarter financial results, a discussion of operations, and Pennsylvania, Texas, and Oklahoma. Additionally, I will discuss our Outlook for the next 15 months for Cabot. But before I get into details on these topics, let me start with a summary of our impressive results so far, year-to-date, in 2011 and a quick overview of expectations for 2012.

In 2011, Cabot will grow production in the 40% to 46% range, net of asset sales. We will grow reserves 10% plus. We will reduce, or at a minimum, maintain total debt at a level below $1 billion. This is all generated by a program that encompasses a total rig count of 7, which I think indicates the prolific nature of our portfolio. If we look ahead to 2012, our expectations will be, and this is off of a larger base, grow production between 45% and 55%. We will grow reserves, again, 10% plus, maintain a reduced debt without asset sales and, again, all generated from a total rig count of 7. I think from the guidance I have seen from industry, Cabot's numbers are unmatched. In fact, I have been in the business for over 30 years, and it is rare that I have seen numbers that can demonstrate this amount of growth in a cash-flow neutral to cash-flow positive program.

Cabot's financial reported for third quarter, had clean earnings of $35 million and with discretionary cash flow of $165 million. This quarter continued the consistent trend of low natural gas price realizations offset by very robust production growth. We expect natural gas prices to remain range-bound through the remainder of 2011 or until seasonal factors kick in. Additionally, we do anticipate further production advances for the remainder of the year as infrastructure capabilities do become available. Though we have not included these in our fourth-quarter guidance. In terms of third-quarter production, the company posted a 39% growth rate between comparable third quarters reporting 50 BCF. We continue to enjoy high growth rates from our gas portfolio but I am particularly pleased to see the results of our liquids initiative with over 100% growth in oil and related liquid volumes between comparable third quarters. Clearly, this indicates this increase comes from -- our Eagle Ford effort with more wells coming online.

We do expect to see an ongoing increase in our liquids production. The guidance last night, we posted new guidance with regard to 2012 production. We initiated with a range of growth between 45% and 55%. We provided detail for the first quarter only, due to the fact there are several infrastructure projects in the works with estimated 2012 start dates. As we have seen this year, multifaceted projects at time-frames that can slide. Our expectation is we would have a much clearer, more exact timing on this front by the February call when we could give more specific details. With that said, let me emphasize again, at a minimum, we anticipate 2012 production growth to be in the 45% to 55% range.

In terms of 2011 fourth quarter, we maintained our existing guidance with 9 months of actual production of having already exceeded last year's record total level. Our expectation for 2011 will be far and away better than any time in our history. This rate also takes into account the sold production in several infrastructure delays. In terms of infrastructure, Laser just came online this week up in PA, and Springville is still expected in mid-December. Again, no incremental volumes in 2011 from Springville are contemplated for us to stay within our guidance. Cost guidance has been updated with no change in our fourth quarter 2011, however our first quarter of 2012 reflects reduction to operating expense, DD&A, and financing at increased to transportation, G&A, and maintained other taxes and expiration expense. The overall impact in 2012 is a lowering of cost from previous guidance levels. Obviously, the reduction of our unit cost will yield incremental dollars to the bottom line. We do expect this reduction trend to continue throughout 2012.

We have maintained a strong preference to deliver a disciplined approach to capital spending. The asset sales 2011 have allowed the expansion of our current year program to about $825 million to $875 million. You will recall, we said on the second quarter call, the number would move up from the $600 million mark to around $750 million. This slight increase from there is a result of our drilling efficiencies that have allowed more wells to be drilled in Pennsylvania, Texas, and Oklahoma. More completions, although still constrained by infrastructure, and more leasing activity in our key areas and a couple of new ideas. For 2012, we expect our program to be in the range $850 million to $900 million. The planned program range is fully funded at the low end with a $4 gas price and the program generates a cash-flow surplus at the high end with a $4.50 gas price. Bottom line, we have positioned ourselves for one of the highest percent production growth of our peer group while staying within cash flow.

In addition, we are able to achieve our goals with just 7 rigs, an excellent indication of our capital efficiency. Our industry has a tendency to significantly outspend cash flow to achieve, in some cases, a much lower growth rate. No new hedges were added in the third quarter with one 2012 oil hedge added thus far in the fourth quarter. The company has 28 contracts, the remainder of 2011 production, 28 contracts for 2012, excluding the 5 basis-only hedges, and 5 contracts for 2013. You can evaluate those on our website.

Let's move to operations. In the North Region, our Marcellus results in Susquehanna continue to achieve new milestones and let me, again, highlight some of the key records that we have set. New 24-hour production record of 517 million cubic feet per day from only 94 horizontal wells. Cabot's fastest well to produce 3 BCF took only 223 days. Our fastest well to 4 BCF took only 347 days. We are adding drilling efficiencies with our fastest well to TD took just 12.5 days and that was a 3,500-foot lateral. Cabot's area of the Marcellus produced 16 of the top 20 wells in PA during the first half of 2011. During the quarter we turned in-line a total of 18 wells, 17 horizontals, and one vertical well. The sum of the production of these new wells was 153 million cubic feet per day, but the production was curtailed due to infrastructure restrictions.

Currently, we have 4 rigs operating in Susquehanna with an additional new build scheduled to arrive in November. Also, we currently have a total of 497 stages in various phases of completion. 213 of those are being completed, or cleaning up, or waiting to turn inline. 284 of those are waiting to be completed. We continue to make progress on the many infrastructure projects that will ultimately create one of the largest takeaway capacity systems in the United States. This week was the initial in-service date of our Laser pipeline located in the northern area of Cabot's leasehold in Susquehanna. The Laser pipeline is ultimately designed to carry 150 million cubic feet per day of Cabot's production for sales into the Millennium pipeline system in New York. At Laser, we currently have a total of 4 wells cleaning up into the line.

We have been asked about the Marcellus in the northern portion of our acreage. The gross section is slightly shallower and is approximately 240 foot thick versus approximately 350 foot thick where we have been drilling. Keep in mind, the thickness we see in this northern area remains considerably thicker than the Marcellus seen throughout PA. We anticipate keeping a rig active in the north area and adding volumes throughout the fourth quarter. We are excited to have Cabot's Marcellus production into a new marketplace.

Next, we are anxiously awaiting the start up of Springville pipeline, now scheduled for early December. Significant progress has been made to date including the completion of the compression station. Significant progress on the major bores and completion of the tap into the Transco pipeline. This is great news as we await the finishing touches on the 24-inch pipeline. Transco, just like the millennium pipeline, represents new markets for Cabot to immediately access.

One new development we are excited about regarding Springville, which we did release last night, is that Cabot and Williams have agreed to terms regarding the unsubscribed capacity on Springville, essentially increasing our position from 300 million cubic feet per day of takeaway to 625 million cubic feet per day. This additional capacity will be available mid 2012. With this as a backdrop, the majority of our 2012 production will be going to markets not served today by Cabot, which we think is an improvement. When you combine the incremental capacity of 325 million per day to the pre-announced plans for our infrastructure, our mid year 2012 takeaway now stands at 1.325 BCF per day, and the year-end total takeaway capacity grows from the 1.2 BCF per day to 1.525 BCF per day.

Let me also add that various other projects and expansions we have discussed previously are all on track for on-time completion. As we reported last night, with the delays in moving gas on Laser and Transco, we have confined and been combined to deliver all of our Marcellus production into one single 24-inch Tennessee pipeline. With the gas-on-gas competition from the surrounding areas, pricing for our northeast Marcellus producers has seen downward pressure. While we have heard numerous rumors regarding the price we have received for our gas, Cabot's monthly average price in the fourth quarter has remained above $3 per MCF during this soft period. We are mindful that our pending takeaway projects to diversify our production into multiple downstream markets on new interstate pipelines will relieve some of this tension.

Now let's move to the South Region. In our Buckhorn area, in the Eagle Ford, the Company has drilled a total of 24 wells. Each well is a 100% working-interest well in Frio and La Salle County. 21 of these wells are on production with 2 wells completing, 1 well waiting on completion, and 1 well drilling. The 2 most recently completed wells produced at initial 24-hour rates of 938 barrels of oil equivalent per day and 791 barrels of oil equivalent per day. In our AMI area with EOG, there are 6 wells presently on production in this 18,000-plus acre area with 3 of these wells drilled and completed in the third quarter and the results are at anticipated levels. Gross production for both areas in the Eagle Ford is over 7,600 barrels of oil equivalent per day. Cabot intends to drill or participate in 25 to 30 net Eagle Ford wells in 2011.

Now moving to Oklahoma. Beaver County, where we have our Marmaton operation, Cabot has continued its effort there with participation as planned in 7 non-operated wells with a few more to go in this quarter. Last night, we highlighted the latest 2 wells and these wells were a significant uptick from our excellent initially operated well. The second Cabot operated well was spud last week, and the well is designed for a 4,000-foot lateral with approximately 16 frac stages. Cabot intends to drill 2 additional operated wells and will participate in 8 to 10 total non-operated wells in 2011. Cabot now controls approximately 61,500 plus net acres in the play, which is up from the 54,000 we previously announced. We believe the results that we will see in the Marmaton will provide us very favorable economic returns.

In the Heath, we have gathered as much information as we could from a poorly drilled and completed well. We status the well as unsuccessful, and we'll take the information we collected and continue our science work in the area. The science effort drove our expiration cost above guidance, essentially $0.03 for the quarter. Fortunately, we do have long lease terms remaining to work with.

Now, moving to 2012 plans. In Pennsylvania for 2012, Cabot will have, on average, 5 rigs running. We are planning 70 to 78 Marcellus wells. We also anticipate running 1.5 frac crews for the year. In Texas and Oklahoma, we will remain focused on liquids production. In the Eagle Ford, Cabot will drill or participate in 20 to 30 wells. In the Marmaton, we anticipate that the Company will participate in the drilling of between 25 and 30 gross wells with the majority of these wells being operated. Plans call right now for the Company to operate 2 rigs in the south, 1 in the Eagle Ford, and 1 in the Marmaton.

We believe our 2012 program will yield greater efficiencies from a dollar invested perspective than our 2011 program. We will demonstrate operational efficiencies in both drilling and completion along with some moderation in our overall service cost per completed well. Additionally, we continue to improve efficiencies in our vertical integrated operation with our internal construction of locations, roads. We also provide water hauling and handling and frac tanks and other various assundry things that we have in-house.

In closing, Cabot's operations remain simple. We focus our gas efforts solely in the Marcellus and allocate dollars to the oil window of the Eagle Ford and Marmaton, which will drive our double-digit growth in reserves and production, year-over-year, all within an anticipated cash flow neutral program. With that summary, Holly, I will stop and be happy to answer any questions the group might have.

(Operator Instructions)

The first question comes from Brian Singer, Goldman Sachs.

Good morning. Two questions. You made a statement in your opening comments that for the incremental volumes you signed on for Springville for next year would be touching new markets. Can you add a little more color on that and are there any implications in terms of realized prices or costs?

I will let Jeff Hutton handle that.

Good morning. What we mean by that is the new gas going down Springville will enter Transco's pipeline, the [lidee] system. That pipeline goes over to the southern part of New York and actually accesses a number of different utilities and interstate markets that (inaudible) gas pipeline does not currently serve. We should be better off in a number of different ways with new markets both in the northeast and actually down back haul on Transco to the Baltimore and DC areas.

As we see this new capacity come on, is there any change in how we should think about the realized prices or your costs based on the contracting that you have done here?

Not a lot. The gas price that we will receive in the Transco and quite frankly, the Millennium and Tennessee, all that is based primarily on the Appalachian kind of pricing you would normally see against the Dominion Index or Columbia Gas Transmission Index.

Dan, free cash flow at $4.25 gas level and at higher gas prices are a pretty rare event, as you move closer to this period. Can you talk about how you're thinking about allocation of that cash, additional liquids drilling acquisitions, debt pay-down, dividends, et cetera?

Our allocation right now is scheduled basically 2/3-1/3. 2/3 going to Marcellus and 1/3 going towards liquids.

So I guess the way to think about the potential for more substantial free cash flow that you would use that cash to ramp up drilling in the Marcellus at double the rate that you would ramp up the drilling or in terms of capital as you ramp up drilling elsewhere, I'm thinking 2012 and beyond.

Scott wanted to make a comment.

Right now, as you saw, the plan is $850 million to $900 million and that will be dynamic like every year's plan is. Clearly, if we take a snapshot right now, that excess will just be used to pay down the revolver. There is no thought at this point of any kind of dividend increase picking up on what you said. Some of that money, if we have a need in terms of lease expirations or new idea or a new project, some of that could go for some of those new science ideas too.

The next question comes from Brian Lively, Tudor, Pickering, Holt & Co.

Good morning, with the Marcellus capacity at 1.5-plus BCF a day at year-end 2012, when do you think you will actually be able to fill that capacity? I'm looking for is that a 2013 or 2014 event?

That's a good question and it is safe to say that we have very high expectations of our area otherwise we wouldn't have added additional capacity. I think we are being prudent in the market we have today with the commodity price where it is and as we continue to gain efficiencies in our development moving more and more toward a full-blown development mode. Right now we are just going to try to get out of the fourth quarter of 2011 and move into the first quarter of 2012 and we have set our guidance for 2012. We do, believe me, internally have a lot of work going on beyond 2012, but I am not prepared to make those projections.

Okay. Could you maybe comment a little on what are the constraints there? It's great for the free cash flow positive situation with where you are at but is that going to be a throttle going forward giving the returns on the wells, or would you, if able, actually accelerate some of that growth and out spend a little bit?

Right now our plan is to stay within cash flow and fortunately our program has very good capital efficiency within it because of the area we are in that even at a $4 MCF, we can stay within cash flow. We will generate a little bit of positive cash flow at a $4.50 price so I think we are in a very unique situation in that case and we do fully appreciate the present value aspect of enhancing the profile of our cash flow stream, and at the right opportunity, we will take advantage of that but right now, I think it's prudent in this market to stay within what we see as a forward curve and a cash flow neutral program.

Brian, let me add also, the tendency in our industry and part of the dynamic in our industry has been the need to capture leases. This program laid out for 2012 captures the leases, all of the leases that would be expiring in 2012, we have no lost opportunity within that cash-flow neutral program. That would be a dynamic were you might out spend but Cabot doesn't need to do that.

That's fantastic. On the asset sales, do you have an updated expected proceeds? I saw that you gave a closing time for the Rockies in October. What are the total proceeds for the year?

We are probably pushing $375 million.

Okay, Dan, you might have said this in the prepared remarks but I didn't hear it right. What was the breakdown of Marcellus production and Eagle Ford production in Q3?

I did not say that, I will let Scott work through that.

Brian, give me a call afterwards. We did not break it down by that. You get an idea in the press release. The gas production in West Virginia is roughly 50 million Bcf a day. Rocky Mountains for the quarter was roughly 25 million Bcf a day and the rest would be in Pennsylvania.

Okay, that works. Thank you.

The next question comes from Pearce Hammond, Simmons & Company.

Good morning. First question is what is the gas differentials for Susquehanna County that you have embedded in your 2012 guidance?

I will refer to Jeff on that also.

For 2012, we are using the -- again we are selling off the Dominion Index and the Columbia Index at probably $0.08 to $0.10 above NOMIX and I might add that the markets will be accessing on Transco and Millennium. We have seen some downward pressure to the differentials in Pennsylvania on Tennessee. We think that is temporary and once we get to the new market areas, we will see what I will call back to normal pricing at the positive differentials to the NOMIX.

Are you experiencing any service costs released, specifically on the completions side in the Marcellus right now?

For our 2012 program, we are in the process of gathering all of our service costs and closing down some annual contracts for some of our services and it is our expectation, as I mentioned, that our service costs will moderate both in the South Region and the North Region per completed well costs.

Perfect. And then the last question from me, there has been reports that you are in the Smackover Brown Dense and I was just curious what your drilling plans were there as well as what acreage you have leased out?

We have several projects that are out there that our guys work on from an exploratory sense. With it being it being just exploratory in nature, we don't typically comment on what we are doing that far ahead of the curve.

Thank you very much.

The next question comes from Amir Arif of Stifel Nicholas.

Another question in terms of how you're thinking about 2012, what would cause you to increase your rig count from above the 5? I know you've got the take away capacity. You talk about wanting to live within cash flow. If we see an improvement in gas prices, is that the signal you're waiting for or is it simply a matter of trying to do it at a steadier pace?

Our approach to business, as a general comment, is we have so much money to work with. We're going to try and strive to stay within a budget. We set our benchmarks to stay within that budget with the assumption of the gas price we have used in our model. And certainly if we had the opportunity to see an increase in the commodity price from what we have used, certainly we will consider drilling additional wells.

Okay, so there's no desire to hedge in the additional volumes and accelerate production growth?

Hedging will remain a consideration for us. I would love to be able to hedge a strip that would lock in some of what we are discussing here. With that lock-in of a significant hedge position, I think we probably would look at our capital program with those hedges locked in place. A 12-month strip at this stage is in between our $4 and $4.50

That makes sense. Just another question in terms of the 2 wells you highlighted in the Marcellus, the 4 Bs and 3 Bs in less than a year. These are not the extended laterals. Is this something you were doing different on these wells?

No. Geologically, we find ourself and some wells pan out in various different areas that we have been drilling and those are some of the poster boy wells that we have had that produced very well and frankly we do have a couple of wells to see what they will do. We do not restrict as much as we do some of our other wells. These are wells we brought on and allowed them to make up a great deal of our production. That may be the sacrifice of some of the other wells we will pitch back.

And just one final question. Can you give a rough number of how much acreage will be held by production after the end of your '12 drilling?

We anticipate that it'll be, after '12 drilling or '11 drilling?

After the '12 drilling, after the program you have laid out for '12?

After '12 drilling, I'm thinking we'll have -- even though we will come back in after we evaluate the production from those wells, we will have more drilling to come back in to drill in some of this acreage that we do have held by production. I would say 35% to 40%.

At what point do you think you will start doing either more pad drilling or start using some of your more extended laterals that you've been testing? At what point do you start changing the way you are developing these wells?

Again, this is a little bit of a forward look. As we increase our production and we increase our cash flow, once we are able to continue to capture our acreage in a very methodical process, which we are doing right now, and we increase our cash flow enough to allow incremental drilling, I think that is when we will come back in and have those type of pad sites set up for 6-wells, 8-well, 10-well type of pad drilling.

It sounds like that is a '14 or '15 event type of thing before you really start changing?

Well if we continue to grow our production and if we could get a little bit of help from the commodity price, it could be earlier event than that.

Sounds great, thanks.

The next question comes from Gil Yang, Bank of America Merrill Lynch.

Could you comment what you're -- I know you're cleaning up the 4 wells near the Laser area, do you have any comment on what those wells look like in terms of a comparison to the rates you are seeing in the more southern area?

It is still very early and we've only had them on for like 3 days. They are still cleaning up so comparison would be a little bit earlier. -- a little bit early for that. To give you an example, 3 wells into it, on our wells in the southern area, we don't know exactly what they will do at that period of time either. In fact, we have wells that have cleanup going into the 30- to 45- to 60-day period as they continue to clean up. It is way too early to make that statement.

And there's no predictive value in the rate of the cleanup?

There is not.

What is your current average spud to TD for Marcellus?

On well costs?

Days you drill the well.

We are in between 16 to 18 days.

Okay. If you look at your program for 2012 versus the program in 2011, is there proportionately going to be more spent on completions in 2012 than 2011 or is it going to be similar distribution?

No. We are going to spend some more dollars will be spent in 2012 on completions than in '11.

Can you give guidance as to how much is going to be for each drilling versus completion?

We don't have that number. I think from a macro perspective, remember, up until recently we had 1 frac crew in the Marcellus and we have taken advantage of the dynamic, the marketplace up there to have 2 crews for a period of time. As you can see they have worked up, when we had this call in July, we were around 600 stages back logged now were just under 500. We expect that that 500 will decline further as it relates to next year, more of a working inventory between 200 and 300 stages. If you think of the well numbers that we gave in the speech were 70 to 78 wells, assume they are all 15-stage fracs, that will give you the stages for next year, and then incrementally we're going to work off the backlog, 50% of the backlog of 250. That will give you an indication of the number of stages that gets done next year.

Can you just comment on -- you made the comment that you expected services to show some kind of moderation, is there a difference in drilling versus completion costs in the south versus the north? Is there more pressure on completion costs in the south than there is in the north and vice versa for drilling or can you comment on that?

I think the savings we anticipate, simply because the majority of the costs are attached to the completion costs, the majority of what we think we would be able to save in 2012 compared to 2011 will fall on the completions side. We don't expect a great deal of change in the drilling side for actual costs in the north and south, but we do anticipate that in the north, we think we would be able to gain efficiencies with each drilling dollar spent by virtue of our penetration rates.

The next question comes from John Abbott, Pritchard Capital.

My question has already been asked.

The next question comes from Ray Deacon, Brean Murray.

I had a question about current well costs in the Marcellus and also yesterday a range mentioned 5.7 and 6.5 [UCS EUs], EUR, so that looked like about a 30% recovery implying there was some potential of an increase EURs so I was wondering what your thoughts were on that.

As far as comparing the drilling costs, range, and if they are talking about, what area where they talking about?

I think in the southwest they were saying 5.7 and then in Lycoming they were saying they thought about 6.5 was the current number.

The well costs in southwest Pennsylvania, that is shallower over there. As we've been able to see, and as the PA DP has put out on well results, southwest does not deliver quite the rates that we are seeing in the northeast portion of Pennsylvania. As you move west from our area, I think it is also indicative that you don't get quite the rates as you move west into the area that is being drilled, that the IPs or EURs are as robust as what we our seeing in our particular area. As far as the drill costs are in the southeast, they are very similar at the $6.5 million to $7 million range, depending on the number of frac stages.

Your 10 BCF UR well that you booked last year, what recovery factor does that work out to and where could that go?

Again, making the comparison, you use 30% on ranges recovering, keep in mind that again just the geology is such that southwest Pennsylvania has a much thinner section than we have. Our section is 240 feet to 400 feet thick. The in-place reserves we have that section compared to a 70-foot section or so is significantly different. The recoveries that we realize and we are working on right now and have a third-party study out there that will be delivered to us at the end of the year, that is trying to arrive at that recovery factor but we think we are going to see in our particular area with the efficiency of our completions and no liquids in the majority of our reservoir, we don't have any relative perm issues or anything like that, we think we have very, very good high recovery factors that could push the 50% to 60% range.

The next question comes from Marshall Carver from Capital One.

A couple of questions on -- you gave the number of gross wells, 25 to 30 gross wells, in the Marmaton next year, how many net wells would that be?

That would probably be in the range of roughly 16 or so operated wells and then I would estimate another 4 or so net wells that are non- operated.

Just a question on -- you did a great job monetizing Rockies and accelerating in the Marcellus this year, why not monetize some other assets, maybe West Virginia or something next year and accelerate more? Is that something you're considering?

Cabot has consistently evaluated our portfolio and made a number of portfolio rationalizations that has taken advantage of transferring our assets into a higher PB and certainly we will continue to look at that opportunity out there if the market will allow.

The next question comes from John Nelson, Macquarie.

Just as a follow up to the response on Gil's question, are there more spot frac crews available in Northeast Pennsylvania now if you wanted them and as you look into 2012, do you see any constraint in the number of crews you can get dedicated?

I'll let Phil respond to that.

We have been picking up spot crews, we have the 1 we've had full-time and we've been picking up spot crews to do other jobs and right now were not seeing any constraints in 2012.

On the extended laterals that were mentioned in the press release, do you have what the actual lateral length was?

The lateral length, the longest was like 6,100 feet.

And the spacing on that was the same as what you guys have been trying?

The spacing on that was about 250 feet or so and each of those laterals, I think one was 5,500 feet and one was 6,100 feet, 1 had 21 stages and the other 26.

Do you have the amount spent on leasehold in the quarter?

I don't have that, Scott.

We can follow up off-line.

John, it is between $30 million and $40 million.

The next question comes from Biju Perincheril, Jefferies.

Good morning. When you think about the incremental volumes on the Springville line, the short existing compression capacity and the new units coming on next year, is that enough or do we need new compression to get to that 625 on the Springville line?

I would take that one. The answer is yes. The expansion by Williams on Springville will include some additional units at the Wilcox station that will allow them to increase the capacity of the line from 300 to the 625 number. In addition to that there will be some expansion and another new station that Cabot and Williams will develop along the Springville lateral and also around the Tennessee gas pipeline area. There is a lot of moving parts to this and we are well on our way to get all of it wrapped up, at least the big part by mid-year and the rest by year end.

Okay. So I think about, I think you had for next year talked about 2 new compression stations coming on Lenoxville and the Williams Central, are those volumes going to be incremental to which can be moved on Springville or is that rerouting some of that?

That is a difficult question to answer because we are trying to develop a system that has a lot of flexibility to it. Yes, Lenoxville will deliver gas into Tennessee gas pipeline solely, however, the Lathrop station for example and the original till station and a new station we have on the drawing boards, central compression station, those will be able to access multiple pipelines. The design of the system is to have access to 3 different interstate markets, 3 very large markets, and at the same time maintain field pressures we think are ideal to produce these wells into and also access the higher price markets.

Okay, that's helpful. I think you talked about this before, the 2 extended lateral wells you mentioned in the press release, did you say those were not subjected to any sort of -- they were not [shook pack] like some of the other wells that, or were you afraid (inaudible) wells?

They were brought on like our other wells that are brought on at a little bit of a moderated rate to allow us to continue to clean up, but we did allow those to produce into the pipe at fairly aggressive rates however I would add to that we did hold some back pressure for example, as recently as yesterday, the wells were producing above line pressure in the 1,400-pound range.

That's helpful. Thank you.

The next question comes from Bob Christensen, Buckingham Research.

Good morning, thank you. About how much exploratory leasehold has the company booked so far this year, sort of outside the things we know about, Marcellus, Eagle Ford, and Marmaton?

Part of what we can do on our exploration, we just try to stay behind the curtain for as long as we can until all of the scouts discover us out there.

Would you say it's more acreage at this time this year than last year then? Is the Company, because I'm trying to look at a bunch of years, is the Company becoming more exploration savvy and interested? Is the appetite growing in that direction? Or do you just have so much to work with that's so high quality that you know about? I'm trying to get a tendency of the Company.

We love our position and what we have to work with. We have 10-plus years of significant opportunities within our portfolio right now but as far as our Company being exploration savvy and moving out ahead of the curve, a good example of what we have internally already is by virtue, in 2005, when nobody on this line knew what the Marcellus was, Cabot was leasing out in northeast PA for the Marcellus and we didn't talk about it and we didn't bring it up and we just did our internal work and moved forward without anybody finding out about it until somebody discovered it, that we were out there. I think we have the ability in-house and have had the ability in-house to move out ahead of the curve can be reactive and proactive, both, on new ideas.

One final on the Heath if I may, I think there were 5 other wells by industry up there, do you know of any successes in the Heath by others?

So far what I have seen, and I don't have all the detailed data information on the industry drilling up there, the brief reports I have seen I have not been excited about but again, a couple of wells don't kill a play particularly in a large geographic area. We just need to understand it a little bit better and see if it is going to have another potential for us to make an economic play out of it that would compete with our capital efficient dollars.

Thank you very much.

The next question comes from Michael Hall, Robert W. Baird.

Good morning, two quick ones for me. I was curious if you had the rates on the [cumes] that you reported, maybe the average rate for the 2 BCF average for those 30 wells and perhaps the other rates that were reported in the ops update?

The 2 wells that have been of note are still producing well over 15 million cubic feet a day, each.

Okay. And then how about those 2 BCF, didn't you say 30 wells that averaged over 2 BCF a day, I was curious if you had the average rate at the time of those cumes?

I have not averaged those 30 wells.

Okay. Sorry if I missed it but the 2012 Outlook, how many wells do you contemplate tying into sales in the Marcellus program in that outlook?

How many wells do we anticipate tying in? 55 to 65.

That's all I had. Thank you.

They next question comes from Brett Hall, Global Hunter.

Good morning, you provided EUR for Marmaton well?

Yes. Right now, and this was early time and we haven't changed that because we are still gathering significant amount of data and we can see some of the tweaking being done on the amount of profit that we pumped and things and have had some enhancements and compared our initially operated well with the not-operated wells that have been drilled but we are between right now, and again this is based on our first well, 175 to 225 BOE at this particular time and maybe with additional stages, frac stages, and longer lateral lengths that, that number would increase. Keep in mind our initial well was a 10-stage frac.

All right, thank you.

At this time there are no further questions.

I appreciate everybody's attention and just an ending comment, that Cabot provides, and again this is from many years in the business, one of the lowest risk stories to accomplish what I think is an industry-leading result with the cash-flow neutral to cash-flow positive program that generates in excess of 45% production growth and a 10% plus reserve growth with superior capital efficiencies. I don't think you're going to find that in a program that takes about 7 rigs to accomplish those feats. With that I will and it and I appreciate everybody's interest in Cabot. Thank you.

Thank you participating in today's Cabot Oil and Gas quarter 3 2011 conference call. You may now disconnect.