Coterra Energy Inc. (CTRA) Q2 2011 Earnings Report, Transcript and Summary

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 [Operator Instructions] 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 I also have the 2 regional managers, Matt Reid and Phil Stalnaker. Before we start, you're 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'd also like to expand on the press releases that were issued last night. I will briefly cover the second quarter financial results. I'll also have discussions of the operations in both regions, north and south. And I'll cover so the rationale behind the sale of our Rocky Mountains assets and some of the use of those proceeds. Overview should be fairly brief, and I 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 ranged down 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's the highest quarterly production that Cabot has ever reported. We continue to enjoy high growth rate from our gas portfolio, but I'm particularly pleased to see the results of our liquids initiative with over 20% growth in oil volumes. With more wells coming on stream, I would expect this oil and liquids increase to continue. For 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 46%, up from 34% to 42%. This increase is based on the level of gas we are currently producing. The incremental volumes 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 feet 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 buildout 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 result on 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've 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'll be able to drill a few incremental Marcellus wells and replace the sold production as we expand our efforts into high return areas. I'll cover more on the specifics around this capital plan a little bit later. Cabot did add to its hedge book for 2011 and '12 during the quarter, which we've 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 5 basis only hedges that we have and 5 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 were more likely to deliver a debt reduction program after applying the proceeds from the 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 Eagleford and Marmaton oil projects, including a small portion of the $50 million to be allocated towards another liquids-rich idea we are 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 fuel production high of 140 million cubic foot -- excuse me, 440 million cubic foot per day. Some of the wells contributing to this record production include 5 wells completed in the quarter, that each exceeded 20 million cubic foot per day for our 24-hour production rate with ranges between 21 million to 28 million per day. Also, the combined 30-day rate for the 5 wells was 100 million cubic foot per day. As we stated in the release, we indicated the prolific nature of our area in the Marcellus by highlighting 2 wells that have now surpassed the 4 Bcf mark in cumulative production, one of those occurring in only 12 months, the other in 16 months 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'll discuss that in a moment, we continue to add to our production capacity and our inventory. We are running 5 rigs in the Marcellus and a full-time frac crew. We have a total of 259 stages being completed, cleaning up or waiting to turn in line and an additional 323 stages waiting to be completed for a total of 582 stages. As you're aware, we remain constrained by the infrastructure capacity, which currently allows us to flow somewhere in between 400 million and 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 buildout. 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, the project completion has slid slightly into the fourth quarter. To be conservative, we are 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 and the timing that will come about with the buildout. 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’s how some of the numbers breakdown: The Laser takeaway, just with the pipe, is scheduled for October at 50 million cubic foot per day tying into the Millennium line. That we will be able to utilize at that point in time for free cash flow gas. The 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. Beyond that is attached to our Lathrop compressor station. In March of 2012, Phase II of Laser will add an incremental 50 million cubic foot per day. And in April of '12, 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. So when you combine and tie together this in-service dates with both the 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 '12, 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 1 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 initial well in our Heath prospect, located in Rosebud County, Montana, was completed in the second quarter. Now this 8-stage completion is currently on task and recovering load water. The process has taken 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 cleanout run, and we'll be able to give additional information on this in September. Going to the South region, in our Buckhorn area, in the Eagle Ford, the company has drilled a total of 17 wells. Each well is 100%-working interest well in Frio County. 11 of these wells are on production, with 3 wells completing, 3 wells waiting on completion and 2 wells currently drilling. As the press release highlighted, 4 of the 11 producing wells were placed on production during the second quarter. These 4 wells each produced at a combined average initial 24-hour rate of 721 barrels of oil equivalent. Up until now, we have had the flare of the residual gas, as there was no pipeline connection. We're pleased to announce that our new pipeline system now in place at Buckhorn. In partnership with the 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 old 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 2 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 Marmaton well with a 24-hour rate, 592 barrels of oil and 325 Mcf per day for an equivalent total of 646 barrels. The well is drilled with a 4,000-foot lateral and completed with a 10-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 5 to 6 additional non-operated wells to further evaluate the play, along with looking for a rig to drill another operated well or 2. 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 only in the Marcellus and allocate dollars in the oil windows of the Eagleford and now the Marmaton, which will increase 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 lines in several of these areas. We have already highlighted our production expectation post the asset sale, and our reserves are expected to approximate 3 TCF at year end even after taking in 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. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.: Dan, I just have a few questions here. If I got your numbers right, it looks like you'll be adding around 550 million a day by July in 2012 from current production? And if that's 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 those -- that incremental capacity?

Okay, you're right on the capacity increase that we'll see by July '12 is the 550 million, and that's the pipe and the compression. And 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 sale is the clarity and visibility and comfort we have now in getting some of these infrastructure capacity in place. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.: And so if I think about the potential extra CapEx that you spent in the Marcellus, then some of that will be spent -- basically be in front of the infrastructure buildout, 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've done majority of our drilling. When I mentioned Laser, it's to the north, and we have now have some additional drilling. In fact, I 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, and then when I talk about the Lenoxville compressor, that's 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. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.: And you think by mid-next year, you'll 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 aligned 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 half a crew, 2 crews, 2.5 crews, whatever the number is. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.: Okay. And just last question for me, and I'll hop off, but clarification on the Rockies divestiture, what was the run rate unit OpEx for those properties? And then could you maybe provide maybe a clean Marcellus OpEx number with that?

Yes, and I'll 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 $0.05. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.: You said $0.05, did I hear you correctly?

You did hear me correctly.

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

So following up on a question on the point on operating costs there. We did see a decent step down in operating costs this quarter versus last quarter, and I wondered your comments on whether you think we will see further step down beyond the asset mix shift from selling the Rockies assets, but just more -- we will see more step-downs in the cost as you bring more Marcellus production online, 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. We did -- 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. So there was a few little one-off things that caused the number to be lower in the second quarter than we were 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 Eagleford increasing volumes. So just in aggregate, we do expect the unit cost to continue to trend down.

Great. And then separately, can you talk to some of the shallower zones on your Marcellus acreage, the upper Devonian zones, work that you've done there and wells that you've drilled there, and when, and your thoughts?

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

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

No, with the depth of the wells 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.

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

Could you just give some kind of predictions – maybe use another word -- could you give us some kind of anticipation of what you're 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 the 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?

You're correct, and the other area of information that we have.

Would it be fair to say that you're sort of expecting this 6.5 or 10 Bcf type curves, which one would be -- should we be thinking about?

Well, I think it would be fair to ask if they'll be able to get some completions up there and then be able to report back based on the factual data of what our best expectation would be.

So in that context, it sounds like you'll have -- your anticipation that when Laser actually comes online, you should have enough wells that you can fill 50 million very easily even if the wells, let's say, underperform a little bit that you'd 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 pushed our expectation of startup date out a little bit, just simply to be able to plan for weather and delays in the construction process. And the guided volumes that 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. So the 4 four months of Laser production are 4 months at 50 million free flow?

The capacity of the Laser line is 50 million a day in 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 online 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 will be seeing as far as production in '11. It will be a 2012 event.

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

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 kind of the implications of reducing the backlog of uncompleted wells and kind of how that would, in theory, flow through the capital. I'm just making sure I'm thinking about it right. I mean, am I getting that right if I'm 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 kind of capital efficiency rates than would be typical, given that you're really just going to be completing those wells as opposed to needing to drill them as well as complete with them? I mean, I guess, how should we be thinking about that at this point?

Michael, you -- 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 that we had in '10 that we carried over as completions in '11, and we have some carryout 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. And 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 kind of 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.

That makes sense. And I guess, maybe as a 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-to-year. Of that, whatever, 300 some odd stages in waiting on completion categories, what will be -- of that 300, what's kind of what do you think about as a normalized level? I mean, is it half of that you would normally always carry around with you, or is there any color on that?

Yes, 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. That's kind of a -- and that's probably full year, probably better in the summer, maybe not quite as good in the winter. So that would 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's helpful. I appreciate it. And then, I guess, capital cost per well. Just what's the latest and greatest on how much these wells are costing, and have you seen any meaningful inflation? And I guess, any sort of update on the cost front?

We've been -- of course, we have on -- 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 knowing our average cost per well very dependent upon the total lateral lane 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 location adds efficiencies versus drilling maybe 1 or 2 wells per pad. I think we're gaining efficiencies on our construction of our pad sites. We're recycling 100% of our flowback water and also our drill water now. And we're reusing that, so that is creating some efficiencies for us. And we're looking out 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 cost as they are or in fact reduce the cost up there. So our cost per well, per stage, if you will, has not changed dramatically.

Okay. And then, I guess, just 2 quick ones. In terms of the deployment of the monetizations, what -- I guess, of that 340 -- I mean, 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 just lastly, just curious, any comments on what you paid for the acreage in the Marmaton in a kind of per acre basis? What's the run rate there?

No.

Your next question comes from the line of Biju Perincheril with Jefferies. Biju Perincheril - Jefferies & Company, Inc.: Couple of questions. So the income of wells in the Marcellus of I think 15 to 20 you mentioned, that's all from efficiency gains on the drilling front? You're not -- you're still keeping the 5-rig program this year, right?

Right. Yes, we have -- and the 10 to 15 is the kind of the number, Biju, that we're looking at. Biju Perincheril - Jefferies & Company, Inc.: 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 feet a day?

No, the 5 wells came online, each of them over 20 million a day for an IP 24-hour rate. And if you combine what those wells we're producing on the 30-day rate, that rate for those 5 wells total combined is 100 million cubic foot per day. Biju Perincheril - Jefferies & Company, Inc.: 100. Okay. And what were the lateral lengths in frac stages on those wells?

They were -- they varied but they were anywhere from 16 to -- or 15 to 21. And yes, so you can do the numbers on the frac stages. Biju Perincheril - Jefferies & Company, Inc.: Got it. Okay. And then, the Springville pipeline, you mentioned the construction has begun on some stages. Does that need any additional permits at this point, or has William secured all the necessary permits?

I'll let Jeff comment.

My understanding is there's still a couple of outstanding programs to be obtained. I know that the status of those are kind of any day now. But the good news is that construction crews are out and everything is mobilized and just waiting on the last signatures on a couple of permits. Biju Perincheril - Jefferies & Company, Inc.: 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's what we're remodeling. Biju Perincheril - Jefferies & Company, Inc.: Okay. And then one last question around these longer lateral wells that you're drilling. I know not every well are going to be -- that you'll be drilling will be at 15 to 20 stages, but can you just sort of talk about how you're thinking about EUR expectations for these more recent wells that's flowing on the laterals?

Yes. Our 2010 program was basically an average of 14 stages per well. And then as we drive our 10 Bcf EUR expectation, we have more data on our 2010 wells in the production. And honestly, 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've seen from the wells that we've 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.

[Operator Instructions] Your next question comes from the line of Eric Hagen with Lazard Capital Markets.

Dan, question on -- following up on the completions per 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 -- and we're, mid year, we already wells that brought on in '10. I mean, in '11, we're kind of our wells that we completed that were 2010 wells that we completed in 2011, those were early wells we brought on. And now we're getting to drilling and completing some of our 2011 wells, and these 5 wells that we brought on were some of the early wells in our program. And we're seeing, again, consistent results on a per stage basis and we're seeing anywhere from 800,000 to 1 million plus per stage.

Okay. That's very helpful. And then in terms of the rate of drilling, do you have a similar metric in terms of, you said, 60, 70 stages per month. In terms of how many wells you drill for the month per rig, just a broad estimate on that

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

On a per rig basis, for a 12-month period, 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 to your corporate base decline rate?

Yes. We have not, and I'm going to turn it over to Steve Lindeman to fill 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'll let him take a shot at it.

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

And that's on a corporate level for all your production?

On a corporate level, right.

Okay, then it might be a little higher now with the Rockies, is that fair to say because that was pretty mature production or...

That's correct. The Rockies had a fairly flat decline.

[Operator Instructions] Your next question comes from the line of Robert Christensen with Buckingham Research.

A couple of questions on Marmaton, 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 these upcoming wells in the Marmaton that you have?

I'm going to 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%.

And may I ask who the operator might be in most instances?

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

And 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 any of these of 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've mentioned upfront, Dan, that you had another oil or liquids-rich idea in your corporation and when would testing of that, when will we see a Wildcat on that new idea?

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

I perfectly expect that. If I might ask one more, and that is -- I've lost my thread, if I come back, I'll get back in the queue. I've lost what my question was.

[Operator Instructions] Your next question comes from the line of Marshall Carver with Capital One.

Just a question on the well clause. You talked about how they haven't changed, but I just wanted to make sure I had it right in my model. What would you add up to -- what would a 15 to 16 stage well cost drilling complete right now

$6.5 million to $7 million.

[Operator Instructions] At this time, there are no additional questions in the queue.

All right. Thank you, Stephanie. And thank all of you who have joined us and stuck 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 discipline. And like our guidance, increasing even in light of asset sales and the redeployment of the capital into our key areas in the Marcellus, Eagleford and Marmaton is going to set us up well for year-end reserves and also early in increased expectations in '12 for production. I'm very pleased that we're going to have a Bcf capacity takeaway within a year from today and in 2012, with Matt and Phil staying here. And I'm sure the numbers are going to give us, so we can talk to the board that will show reserve growth, production growth. And I would imagine and that it's going to be certainly within a cash flow neutral program and most likely a cash flow positive program in 2012. And certainly, I couldn't ask any more from the team. I appreciate your interest. Thank you.

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