Coterra Energy Inc (CTRA) 2011 Q2 法說會逐字稿

Good morning. My name is Stephanie, and I will be your conference operator today. At this time, I would like to welcome everyone to the Cabot Oil & Gas second quarter 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)

Thank you.

I would now like to turn the conference over to Dan Dinges, Chairman, President, and CEO of Cabot Oil & Gas. Sir, you may begin your conference.

Thank you, Stephanie. Good morning, and I appreciate everybody joining us for this call. I have with me today -- from Corporate I have Scott Schroeder, you all know, Jeff Hutton, Steve Lindeman, and also we have the two regional managers, Matt Reid and Phil Stalnaker.

Before we start, you are aware that the forward-looking statements included in the press release apply to my comments today.

At this time, we have many things to cover and talk about, and I would also like to expand on the press releases that were issued last night. I will briefly cover second quarter financial results. I will also have discussions of the operations in both regions, North and South. And I will cover some of the rationale behind the sale of our Rocky Mountains assets and some of the use of those proceeds. My overview should be fairly brief and will allow ample time for questions at the end.

Cabot reported its financial results for the first quarter with clean earnings of $43 million and with discretionary cash flow of about $147 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, as we have seen in the first half. Additionally, we anticipate robust production for the remainder of the year, which I will outline in a few moments.

In terms of second quarter production, the Company posted a 47.5% growth rate between comparable second quarters, producing 45 BCFE. That is the highest quarterly production that Cabot has ever reported. We continued to enjoy high growth rates from our gas portfolio, but I'm particularly pleased to see the results of our liquids initiative, with over a 20% growth in oil volumes. With more wells coming on stream, I would expect this oil and liquids increase to continue.

On our guidance, with our wells still showing excellent results, last night we posted a new full-year 2011 guidance, increasing the overall growth rate to 40 to 46% up from 34% to 42%. This increase is based on the level of gas we are currently producing. The incremental volume is expected to free flow into the laser pipeline in Northeast PA and an additional interstate outlet expected to occur in the fourth quarter, also in the Marcellus area.

As a footnote, this increase in production guidance has taken in consideration the sale of our Rocky Mountains properties effective September 1, 2011, which is about 27 million cubic foot per day.

Cost guidance has been updated with decreases in operating expense, DD&A, and other taxes, and an increase in G&A and third quarter exploration expense. The net impact is an overall lowering of unit cost from previous guidance levels. Obviously, the reduction of unit cost will yield incremental dollars to our bottom line, and we do expect this trend to continue into 2012. We have maintained a strong preference to deliver a disciplined approach for our 2011 capital spending program. With our wealth of opportunities in the Northeast Pennsylvania area, our continuous progress in the infrastructure build-out up there, and our improved efficiencies and returns of our new liquids-rich ideas, we have decided to monetize a portion of our Rocky Mountains asset base and deploy some of those dollars towards additional drilling in both our North and South regions that will enhance our production profile for 2012.

The assets we sold in the Rockies region were our legacy Green River Basin assets. We did not sell any of our early initiatives, such as the Heath or Chainman. Essentially, we have monetized an asset not valued by the market, providing an opportunity for a multiple value expansion. With the use of a portion of proceeds from this asset sale, we will be able to drill a few incremental Marcellus wells and replace the sold production as we expand our efforts into high-return areas. I will cover more on the specifics around this capital plan a little bit later.

Cabot did add to its hedge book for 2011 and 2012 during the quarter, which we posted in June. This effort now has a Company with 28 contracts for the remainder of 2011 production, 28 contracts for 2012 production, excluding the five basis-only hedges that we have, and five contracts for 2013 production. No new hedges were added since this last posting in June.

Operations, as we have previously discussed, operationally for 2011, our plans remain to deliver a net cash flow-neutral program. In light of our recent asset sales, we will more likely deliver a debt-reduction program after applying the proceeds from these sales.

With that as a backdrop, we are evaluating adding $80 million to $100 million to our Marcellus program to drill 10 to 15 additional wells for the full year, along with the South to invest about $50 million for the Eagle Ford and Marmiton oil projects, including a small portion of the $50 million to be allocated towards another liquids-rich idea we're working on.

Now let's move specifically to the regions. In the North Region, the wells in Susquehanna continue to exceed our expectations. We achieved a new one-day field production high of 140 million cubic foot per -- excuse me, 440 million cubic foot per day. Some of the wells contributing to this record production include five wells completed in the quarter that each exceeded 20 million cubic foot per day for a 24-hour production rate, with the ranges between 21 million to 28 million per day. Also, the combined 30-day rate for the five wells was 100 million cubic foot per day.

As we stated in the release, and we indicated the prolific nature of our area in the Marcellus by highlighting two wells that have now surpassed the four BCF mark in cumulative production, one of those occurring in only 12 months, the other in a 16-month time period, respectively, with these wells still producing at a combined rate of over 10 million cubic foot per day.

As we anticipate the completion of some takeaway infrastructure in the near-term, which I will discuss that in a moment, we continue to add to our production capacity and our inventory. We are running five rigs in the Marcellus and a full-time frac crew. We have a total of 259 stages being completed, cleaning up, or awaiting to turn in line and an additional 323 stages waiting to be completed, for a total of 582 stages. As you are aware, we remain constrained by the infrastructure capacity, which currently allows to us flow somewhere in between 400, 440 million cubic foot on any given day through the Teel and Lathrop into the Tennessee 300 line.

The additional flow capacity is tied to interstate takeaway capacity, which will remain static, as I mentioned, until the completion of the Williams Springville line, which is tied to our Lathrop station running down to Transco to the south, and/or the completion of the laser pipeline from the northern portion of our acreage, which will run to the north and tie into the Millennium pipeline. Now everybody is anxious, just as we are, to receive the news and see the progress of this infrastructure build-out, in particular, the Springville pipeline and its status. I'm pleased to announce that the pipeline construction has begun on segments of the pipeline, and significant progress has been made regarding the installation of their compressor station, located in Wyoming County. However, even under the best circumstance, project completion has slid slightly into the fourth quarter. To be conservative, we're modeling a December in-service date, which is reflected in our guidance.

In addition to the Springville line, the laser pipeline to the north, going to attach to Millennium, is also currently under construction, with an early fourth quarter in-service date. We have begun completion activities on the handful of wells targeted for completion and connection to the laser line, again, anticipating some modest production adds for the fourth quarter in our guidance. So as of today, Cabot has pipeline capacity up to 440 million cubic foot per day and compression capacity up to 550 million cubic foot per day.

Now let me get into the future plan and describe what is going to come about in the timing that will come about with the build-out. First I'm going to address just the pipeline and the timing of the pipeline, and then I'm going to discuss compression and the timing of the compression installation. At the end of these numbers, I will circle back around and give you a summary of the key dates to look for and some of those volumes when you tie the pipeline and compression capacity together.

So first off with the new pipeline capacity expected in the fourth quarter and throughout 2012, here is how some of the numbers break down. The laser takeaway, just with the pipe, is scheduled for October at 50 million cubic foot per day, tying into the Millennium line. That will be able to utilize at that point in time for free-flow gas. Springville takeaway, heading to the south, is anticipated, as I mentioned, in December, and that pipeline has the capacity at 300 million cubic foot per day to carry down to Transco. Again, that is attached to our Lathrop compressor station.

In March of 2012, Phase 2 of laser will add an incremental 50 million cubic foot per day. And in April of 2012, the Lenox takeaway pipeline will have an incremental 150 million cubic foot per day, which the Lenox is tied to Tennessee. Again, I do plan on circling back around and tying these numbers together.

Now let me move to the compression capacity, which is expected to be installed and commissioned in 2012. The laser compression in March of 2012 will be the 50 million cubic foot per day. The Lenoxville compression, which will be in April of 2012, will be at 150 million cubic foot per day. And Williams central compression, which is July of 2012, will be 300 million cubic foot per day.

All right. So when you combine, tie together the in-service dates with both pipeline takeaway and compression capacity, the true takeaway ability from our wellhead into the market is going to be as follows, and these are really the key dates that you ought to focus on. The laser pipeline in October of 2012, we anticipate having the capacity -- excuse me, in October of 2011, we anticipate having the capacity of 50 million cubic foot per day that we could free-flow some gas. In December of 2011, we anticipate that the Springville line will be available at about 100 million cubic foot per day. In March of 2012, the laser pipeline will add an incremental 50 million cubic foot per day. In April of 2012, the Lenoxville compression pipeline will have 150 million cubic foot per day. And the central compressor that I discussed for Springville in July of 2012 will have an incremental 200 million cubic foot per day.

So, to sum it up, we will be adding 550 million cubic foot per day of total takeaway capacity, which includes pipes and compression, to the current capacity of 440 million cubic foot per day, to give us a total takeaway of approximately one BCF per day by mid-2012. We also have other modifications and expansions planned and have not changed our original target of 1.2 BCF per day of total takeaway infrastructure by year-end 2012. If you have any questions and I botched any of that, Jeff Hutton is sitting beside me and he will be able to clarify.

Also in the North Region, Cabot's initial well in our Heath prospect located in Rosebud County, Montana, was completed in the second quarter. This eight-stage completion is currently on task and recovering load water. The process is taking longer than anticipated. However, we have recovered about 20% of our frac load to-date. The well initially flowed, and as anticipated, we did place the well on pump. We're still optimistic on this completion, and we're in the process currently of making a well bore clean out run, and we'll be able to give additional information on this in September.

Moving to the South Region, in our Buckhorn area, in the Eagle Ford, the Company has drilled a total of 17 wells. Each well is a 100% working interest well in Frio County. 11 of these wells are on production, with three wells completing, three wells waiting on completion, and two wells currently drilling. As the press release highlighted, four of the 11 producing wells were placed on production during the second quarter. These four wells each produced at a combined average initial 24-hour rate of 721 barrels of oil equivalent. Up until now, we have had to flare the residual gas, as there was no pipeline connection.

We're pleased to announce our new pipeline system now in place at Buckhorn in partnership with TexStar Midstream Services. The pipeline infrastructure commenced service in early July, and approximately 3 million cubic foot per day are presently being produced into the pipeline. Our oil pipeline infrastructure is scheduled to be in service early in the fourth quarter. Both projects will greatly enhance our overall operation in the Eagle Ford area.

In our AMI area with EOG, there are two wells presently drilling in this 18,000-plus acre area. Cabot intends to participate, in total, 25 to 30 net Eagle Ford wells in 2011.

Also covered under our South Region and moving up to Oklahoma and Beaver County, Cabot completed its first Marmiton well with a 24-hour rate of 592 BO, barrels of oil, and 325 MCF per day for an equivalent total of 646 barrels. The well was drilled with 4,000-foot lateral and completed with a ten-stage frac for around $4 million. The well averaged 368 barrels plus 130 or so MCF per day for the first 30 days and 320 barrels of oil and 189 MCF per day of gas for the first 60 days.

It's a little early to discuss EURs, but a range we could throw out would be an expectation of 175 to 225 MBOE. We're very pleased with these results, and Cabot's immediate plans are to participate in five to six additional non-operated wells to further evaluate the play, along with looking for a rig to drill another operated well or two. Cabot has increased its acreage position in the area as a result of these early results to over 32,000 net acres.

In closing, Cabot's operational program remains simple -- focus our gas efforts solely in the Marcellus and allocate dollars in the oil windows of the Eagle Ford and now the Marmiton, which will increases our oil reserves and oil production year-over-year. With asset sales now closed or moving towards a close, we're going to take advantage of additional dollars to enhance our 2011 year-end reserves and the opportunity to increase our early 2012 production capacity expectations.

Additionally, we will be securing more liquids-rich acreage to improve our lie in some of these areas. We have already highlighted our production expectation post the asset sales, and our reserves are expected to approximate three TCF at year-end, even after taking into consideration the asset sale effort. So as we increase reserves, increase production, and add more acreage to future drilling opportunities, we will also most likely be reducing our debt year-over-year.

With that quick summary, Stephanie, I will be more than happy to open up the lines for questions.

(Operator Instructions)

Your first question comes from the line of Brian Lively with Tudor, Pickering, Holt.

Good morning, Dan.

How are you doing, Brian?

Doing all right. Thanks for all the details. It was really helpful.

Just have few questions here. If I got your numbers right, it looks like you will be adding around 560 million a day by July of 2012, from current production. And if that is right, my question is, will you be able to immediately fill those pipes with curtailed production or will there be some delay where you need to drill to fill that incremental capacity?

You are right on the capacity increase that we'll see by July '12 is the 550 million, and that's the pipe and the compression. As far as the timing of filling that additional capacity, we have not -- obviously have not put out our guidance, and we would hope to be able to put our guidance out in October of this year. I think one of the reasons we have made the decision to use some of the proceeds from the asset sales is the clarity and visibility and comfort we have now in getting some of this infrastructure capacity in place.

If I think about the potential extra CapEx that you spend in the Marcellus, then some of that will be spent to basically be in front of the infrastructure build-out, as you just said, now that you have more confidence of the timing of it?

Exactly, and some of the clarity around that point is that now when we talk about the Springville line, it's running from our Lathrop station in and around an area we have done the majority of our drilling. When I mentioned Laser, it is to the north, and we have now had some additional drilling, in fact have a frac crew up in that particular area as we speak, but we haven't done a lot of drilling up in that area. When I talk about the Lenoxville compressor, that is to the east of our Lathrop station on the Tennessee 300 line. We have done some drilling over there, but we plan on doing incremental drilling in those 2 additional areas to add the capacity to meet the expectation.

And you think by mid next year you will be able to basically work down that -- I think you said 580-ish stages that's waiting on hookup or completion?

Some of the plan that we have to present at our October board meeting is the bottoms-up-build budget that the regions are doing. And that budget build will take in consideration these capacity and takeaway opportunities that we have, align the drilling, along with the frac crews, to be able to position and coordinate and be as efficient as we possibly can to fill those particular volumes. So, I have not gotten the final run from the regions yet on how many frac crews that we'll have, but certainly, we anticipate being able to frac more wells and add a half a crew, two crews, two and a half crews, whatever the number is.

Okay. And just last question from me, and I will hop off, but clarification on the Rocky divestitures. What was the run rate unit OpEx for those properties, and then could you maybe provide a clean Marcellus OpEx number with that?

Yes, and I will let Scott take that one.

Right now, Brian, through the first 6 months of 2011, our direct operation expense in the Rockies was $0.81, and that comparable number for our Pennsylvania operation in aggregate, which is the Marcellus operation, is a nickel, $0.05.

You said $0.05, did I hear you correctly?

You did hear me correctly.

Okay, great. Thanks a lot, guys.

Thanks, Brian.

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

Thank you. Good morning.

Hi, Brian.

Following up on the question on -- or the point on operating costs there, we did see a decent a step down in operating costs in this quarter versus last quarter. I wondered, your comments on whether you think we will see further step-downs beyond the asset mix shift from selling the Rockies assets, but just would we see more step-downs in cost as you bring more Marcellus production on-line? Or whether this is a good run rate, especially considering that there will be some liquids coming on over time as well?

Brian, this is Scott.

From what we had out there previously for the third and fourth quarter, we did move operating LOE down a little bit. The dynamic in the second quarter were some credits that came through, particularly in the West Virginia operation, where we had paid for some before and then it was reversed in this period. There were a few little one-off things that caused the number to be lower in the second quarter than we are forecasting in the third and fourth quarter, but we do expect that trend to continue to decline throughout the rest of this year and then throughout '12. Driven, like you said, by those volumes that were -- the Marcellus production increasing volumes, the Eagle Ford increasing volumes. So, just in aggregate, we do expect unit costs to continue to trend down.

Great. Thank you.

And separately, can you talk to some of the shallower zones on your Marcellus acreage, the upper Devonian zones, work that you have done there, wells that you have drilled there, and your thoughts?

We're still evaluating the -- not only the zones shallower, but also slightly deeper than our Marcellus. And we, really at this stage, don't have a whole lot of color to add, Brian. But you can be assured that we are evaluating it.

Thanks.

And lastly, on the Heath well, when you originally -- in your original plans, would you have originally expected to have put it on pump this quickly? Or is just putting it on pump at this time in line with your expectations?

With the depth of the well and our early expectations, we anticipated having to put it on pump. And what slowed it down considerably is just the timing of doing all of this. But we did anticipate putting it on pump this early.

Great. Thank you.

Your next question comes from the line of Gil Yang with Bank of America.

Good morning, everyone.

Could you just give some kind of -- predictions is not the right word -- but could you give some kind of anticipation of what you are expecting wells in the Laser area to come in at. And have you tested those wells or are you just sort of looking at logs and anticipating the productivity?

We have not tested wells. As I mentioned, we just have moved the frac crew in up there. But we anticipate fairly robust rates.

Just from looking at logs?

Correct, and the other area information that we have.

Would it be fair it say that you are sort of expecting this 6.5 or 10 BCF type curves, or which one should we be thinking about?

I think it would be fair to us to be able to get some completions up there and then be able to report back based on the factual data what our best expectation would be.

So, in that context it sounds like you will have -- your anticipation that when Laser actually comes on-line, you should have enough wells that you could fill 50 million very easily, even if the wells -- let's say underperformed a little bit, that you would have enough spare deliverability that you could hit 50 million.

Yes. And to address it through expectations, we have in our guidance included some of those volumes to be free-flowing into the Laser connection. And as we did previously on the expectations of Springville line and other improvements to the infrastructure, we push our expectation of start-up date out a little bit, just simply to be able to plan for weather and delays in the construction process. And the guided volumes we have free-flowing and expect to free-flow into Laser is no exception to, maybe, our conservative approach to lay out guidance.

So, just to clarify, the four months of Laser production are four months at 50 million free-flow?

The capacity of the Laser line is 50 million a day free-flow, that is starting in October. So, that would be really 3 months, and the guidance has incorporated the expectation that we anticipate flowing up there.

Okay.

And for the accelerated -- for the additional wells you plan to drill in the different areas, is that additive to volumes in 2011 or is it more building up inventory that will come on-line in 2012?

That would be tacked on the end of our drilling program for 2011, and I would venture to say that all of those wells would not -- not any of those wells would be seen as far as production in '11. It would be a 2012 event.

All right. Thank you very much.

Thank you.

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

Thanks. Good morning, all.

Good morning.

Great update.

Just curious, I guess a few things. Most of my stuff has been answered. A little more color maybe on the 2012 outlook as it relates to capital and the implications of reducing the backlog of uncompleted wells. How that would, in theory, flow through to capital, just make sure I'm thinking about it right. Am I getting it right if I am thinking that the incremental volumes that are likely to come on in '12? However we choose to model them, likely come on at much higher capital efficiency rates than would be typical, given that you are really just going to be completing those wells as opposed to drill them as well as complete them? I mean, I guess, how should we be thinking about that at this point?

Michael, and again, the way you model it and the way you probably have modeled it, each year we do have wells that we carry over. For example, from 2010 to 2011, we had drilling wells in '10 that we carried over as completions in '11, and we'll have some carry out wells out of '11 into '12. But I think with your comment on the capital efficiency and working down the backlog in '12, Phil and his guys have been working on this 2012 program. As we continue to improve our efficiencies, do those things that now we can start looking forward to improving on, I do anticipate our capital efficiency to improve, and I think it is.

So, I know that might not answer your question directly, but I do anticipate working the backlog of wells off. But I also anticipate having a larger capital program up there that would allow us to stay, if you will, ahead of the game.

You know, that makes sense. And I guess, maybe the follow-up then, how would I think about or how do you think about kind of a normalized run rate, if you will, of wells in backlog? Like you said, obviously, you always carry some over year-over-year. Of that whatever, 300-some odd stages in waiting on completion category, what would be -- of that 300, what do you think about as a normalized level? Is it half of that you would normally always carry around with you? Any color on that?

Let me throw out some numbers. A frac crew will -- and we're using rough numbers -- a frac crew is going to deliver completed 60 to 70 stages a month.

Okay.

And that is kind -- that is probably full-year, probably better in the summer, maybe not quite as good in the winter. So, that will give you a little bit of a benchmark to use in trying to answer that number. But I think looking at a backlog or an inventory, something along half of what we're carrying right now might be a reasonable expectation.

Okay. That is helpful. Appreciate it.

Then I guess capital costs per well. Just what is the latest and greatest on how much these wells are costing, and have you seen any meaningful inflation, and I guess just any sort of updates on the cost front?

Of course, we have -- on the inflation side, we have locked in our services on an annualized basis. We are talking and looking at extended contracts into our 2012 program. But the way our average cost per well is very dependent upon the total lateral length and the number of stages, and we have not seen a great deal of difference in those costs.

I would anticipate at some point in time to gain efficiencies with keeping a rig maybe on location a little bit longer. To drill more wells on a location adds efficiencies versus drilling maybe one or two wells per pad. I think we're gaining efficiencies on our construction of our pad sites. We're recycling 100% of our flow back water and also our drill water now; and we're reusing that. So, that is creating some efficiencies for us. And we're looking at the logistics of moving water up there, which is a fairly big cost to improve on those types of logistics.

So, we're doing things to keep the costs as they are, or in fact, reduce the costs up there. So, our cost per well per stage, if you will, has not changed dramatically.

Okay.

And then I guess just two quick ones. In terms of the deployment of the monetizations, I guess of that 340, is it maybe half of that gets deployed this year? Any additional color there?

Yes, I would say that would be a decent number to look at.

Okay.

And then lastly, just curious, any comments on what you paid for the acreage in the Marmiton on kind of a per acre basis? What is the run rate there?

Nope.

Worth a shot.

Thanks, guys. Congrats.

All right, Michael. Thank you.

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

Good morning, everyone. Congrats on another great quarter.

Thanks, Biju.

Couple of questions. The income of the wells in the Marcellus of, I think 15 to 20 that you mentioned, that is all from efficiency gains on the drilling front. You are still keeping the 5-rig program this year, right?

Right. Yes. And it was -- 10 to 15 is kind of the number, Biju, that we're looking at.

Okay. And I just want to make sure I got this correct, the 5 wells that you completed in the quarter, did you say that the combined 30-day rate was 140 million cubic foot a day?

No. The 5 wells came on-line, each of them over 20 million a day for an IP 24-hour rate, and if you combined what those wells were producing on the 30-day rate, that rate for those 5 wells total combined is 100 million cubic foot per day.

100, okay. And what were the lateral lengths and frac stages on those wells?

They varied, but they were anywhere from 16 to -- or 15 to 21.

Okay.

So, you can do the numbers on the frac stages.

Got it.

And then the Springville pipeline, you mentioned construction has begun on some stages. Does that need any additional permits at this point, or has Williams secured all the necessary permits?

I will let Jeff comment.

My understanding is there are still a couple of outstanding permits to be obtained. I know that the status of those are kind of any day now, but the good news is that the construction crews are out, and everything is mobilized and just waiting on the last signatures on a couple of permits.

Okay. And then once you have those permits secured, the last bit, do you know how many days will it take to complete? What are the remaining phases of construction?

Well, like we mentioned earlier, we're anticipating production in our guidance around December 1, and Williams can probably give you a better update on exactly the in-service date, but that is what we're modeling.

Okay.

And then one last question, around these longer lateral wells that you are drilling. I know not every well that you will be drilling will be at 15 to 20 stages, but can you talk about how you are thinking about EUR expectations for these more recent wells with the longer laterals?

Our 2010 program was basically an average of 14 stages per well. And that's -- we derived our 10 BCF EUR expectation. We have more data on our 2010 wells in the production and obviously the decline curves, and we've been very pleased with what we've seen on the curve fit compared to our 10 BCF EUR. Our 2011 program, we anticipate the average number of stages to be somewhere between 15 and 16 stages as an average on our '11 program.

So, I can't and do not have the information to make and speculate on the EUR prediction for our 2011 program. The only thing I will say is that on a per stage basis and seeing the consistency that we have seen from the wells that we have completed, we have been very pleased. And we don't have a large delta between -- in the detailed way we assess production on a stage basis.

Okay. That is helpful. Thank you.

(Operator Instructions)

Your next question comes from the line of Eric Hagen with Lazard Capital Markets.

Hi, Dan. Question on following up on the completions for a stage, what do you think is a good sustained rate, say over 30, 60 days to model production per stage?

Well, I don't know. I'm not going to break it down that low, but the 5 wells that we brought on, all good wells that -- and we're mid-year. We had our early wells that we brought on in '10 -- I mean in '11 -- were our wells that we completed that were our 2010 wells that we completed in 2011. Those were our early wells we brought on, and now we're getting to drilling and completing some of our 2011 wells. These 5 wells that we brought on were some of the early wells in our '11 program. And we're seeing, again, consistent results on a per stage basis, and anywhere -- we're seeing anywhere from 800,000 to 1 million-plus per stage.

Okay. That is very helpful. Thanks.

And then in terms of the rate of drilling, do you have a similar metric in terms of -- you said 60 to 70 stages per month. In terms of how many wells you can drill per month, per rig, just a broad estimate on that?

Yes, I'm going to let Phil Stalnaker respond to that. Thanks, Eric.

On a per rig basis for, say, a 12-month basis, we're looking at 14 to 15 wells per rig.

Per year.

Per year. So, a little over a well per month.

Okay. Great.

And the final one I had was, any general guidance as to your corporate-based decline rate?

Yes. We have not, and I am going to turn it over to Steve Lindeman to field that, Eric. But to kind of cover for him a little bit, I'm sure he hasn't incorporated, now, our total decline from the sale of our Rockies, but I will let him take a shot at it.

Thanks, Dan.

Eric, we only, again, evaluate reserves at year-end. So, like Dan said, we hadn't incorporated the Rockies sale into the picture. I would say we're kind of in the maybe 10% to 12% decline rate would be my guess.

And that is on a corporate level for all your production?

On a corporate level, right.

Okay. That might be a little higher now with the Rockies, is that fair to say? Because that was pretty mature production?

That is correct. The Rockies had a fairly flat decline.

Okay. That is great.

Thanks a lot, gentlemen. Great quarter.

Thank you, Eric.

(Operator Instructions)

Your next question comes from the line of Robert Christensen with Buckingham Research.

Thank you and very nice job.

A couple of questions on the Marmiton, if I might. When did you begin the science in-house on this? And when was the leasing taking place?

Robert, we began looking at this a little over 2 years ago.

Okay. Very good.

Another question, if I might. The percentage of non-op in those upcoming wells in the Marmiton that you would have?

I am going let Matt Reid, our South Region VP, to answer that.

Robert, it's got a wide variation. It's anywhere from about 3% to 30%.

May I ask who the operator might be in most instances?

I will say it's a very prominent player in that particular area in Beaver County. Let's put it that way.

If I might, again, continuing on, of the 6 to 9 non-op wells, are any of them going to have longer laterals than your Wildcat?

Well, we don't know yet. We haven't seen the EFEs for those wells as of yet. The one well that is now being tested or drilling will have one similar to our well.

And if I just might press on a little bit, I believe you mentioned up front, Dan, that you had another oil- or liquids-rich idea in your corporation, and would -- when would testing of that -- when we would see a Wildcat on that new idea?

Well, on our -- I appreciate the interest in that, Robert, but on those type of projects that, as you can appreciate, the competitive aspects of any liquids dev, I know timing doesn't disclose a lot of information, but we would prefer to talk about the information after we have secured data versus speculating on timing.

I perfectly respect that. Thank you.

If I just might ask one more and that is -- I have lost my thread. If I come back, I will get back in the queue. I have lost what my question was.

Okay. Thank you, Robert.

Thank you very much.

(Operator Instructions)

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

Good morning.

Just a question on the well costs. You talked about how they haven't changed, but I just wanted to make sure I had it right in my model. What would a 15- to 16-stage well cost to drill and complete right now?

$6.5 million, $7 million.

Okay. That is my question. Thank you.

(Operator Instructions)

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

Thank you, Stephanie, and thank all of you who have who have joined us with the call up to this point.

The takeaways, just to kind of reiterate, I think we've done a decent job on keeping our capital disciplined. I like our guidance increasing, even in light of asset sales and the redeployment of the capital into our key areas in the Marcellus, Eagle Ford, and Marmiton is going to set us up well for year-end reserves and also early and increased expectations in '12 for our production.

Very pleased that we're going to have a BCF of capacity takeaway within a year from today. In 2012, with Matt and Phil sitting here, and I'm sure the numbers that they are going to give us, so we can talk to the Board. That we'll show reserve growth, production growth, and I would imagine in that it's going to be certainly within a cash-flow neutral program. And most likely a cash-flow positive program in 2012. And I certainly couldn't ask any more from the team. Appreciate your interest. Thank you.

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