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Executives

Dan O. Dinges - Chairman, Chief Executive Officer, President and Member of Executive Committee

Jeffrey W. Hutton - Vice President of Marketing

Scott C. Schroeder - Chief Financial Officer, Vice President and Treasurer

Steven W. Lindeman - Vice President of Engineering & Technology

Analysts

Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Pearce W. Hammond - Simmons & Company International, Research Division

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Gilbert K. Yang - DISCERN Investment Analytics, Inc

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Robert L. Christensen - The Buckingham Research Group Incorporated

Joseph Stewart - Citigroup Inc, Research Division

Cabot Oil & Gas (COG) Q4 2012 Earnings Call February 22, 2013 9:30 AM ET

Operator

Good morning, and welcome to the Cabot Oil & Gas Fourth Quarter 2012 Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Dan Dinges. Please go ahead, sir.

Dan O. Dinges

Thank you, Laura, and good morning, all. Thank you for joining us for this call. I have in the room with me today, Scott Schroeder, our CFO; Jeff Hutton, our VP of Marketing; Steve Lindeman, VP of Engineering and Technology; Matt Reid, who runs our South Region; and Todd Liebl, our VP of Land and Business Development.

Let me say, the standard boilerplate language and forward-looking statements on our press releases do apply to my comments today. What I do plan on covering today is our full year 2012 operating and financial results, our year-end 2012 reserve analysis, an update on our expectations for '13, followed by an update on the operations, specifically in the Marcellus, Eagle Ford, Marmaton and Pearsall.

Before I do go into the details of our operation, let me start with the highlights from this last night's press releases, and I think these are worth repeating. For 2012, we produced a record 267.7 Bcfe at an increase of 43% over 2011, representing the second consecutive year of production growth exceeding 40%. Despite a challenged natural gas price environment for most of the year, we recorded record revenues of $1.2 billion, which represents the first time our company has exceeded the billion-dollar mark. Additionally, we also achieved record cash flow from operations and discretionary cash flow numbers.

We grew our reserves, our year-end reserves, proved reserves, by 27% to 3.8 Tcf. This growth, we generated 100% organically. We replaced 417% of our production at an all source finding cost of $0.87 per Mcfe, which included an all source finding cost in our Marcellus area of $0.49 per Mcf.

Okay. Now let's move to the financial operational results for the full year of '12. The company reported clean earnings of $138.9 million or $0.66 per share. Cash flow from operations and discretionary cash flow were up 30% and 24%, respectively, compared to 2011. The increase was driven by higher equivalent production and higher realized crude oil prices that more than offset weaker natural gas prices. Total per unit cost, which includes financing, decreased to $3.69 per Mcfe in 2012, which is down 9% compared to '11, as all operating expense categories decreased on a per unit basis in '12, except for our transportation and gathering and taxes and other income.

Okay. 2012 was a milestone year for the company operationally as we achieved 1 Bcf per day of gross Marcellus production and 1 Bcfe total company net production during December. For the full year, we continued to provide best-in-class production growth, achieving a level of 42.3%. This includes natural gas production growth of 42% and liquids growth of 67%. The fourth quarter was especially strong for us operationally in the Marcellus as we grew natural gas production 19% sequentially over the third quarter.

Now let's move into our year-end reserve report. As I mentioned, year-end proved reserves were up 27%, representing consecutive years of significant reserve growth. In addition to the previously stated metrics, 926.8 Bcfe of additions were recorded from our 100% organic drilling program, along with 188.6 Bcfe positive revisions, which is impressive given the negative revisions we have seen across the industry due to a 33% decrease in the benchmark pricing used for booking natural gas reserves. The 188.6 Bcfe of total revisions includes 369.6 Bcf of positive performance revisions, primarily in the Marcellus, which is offset by negative pricing and reclassification revisions primarily in the South area.

Specifically, in the Marcellus, we increased our reserve bookings on PUD locations from an EUR [estimated ultimate recovery] of 7.5 Bcf to 9 Bcf per well based on the results we see throughout the play. Based on 41 producing wells, our typical well for the 2012 program was drilled at a lateral length of 4,087 feet with 17.6 frac stages and an EUR of 13.9 Bcf, which further highlights the truly unique nature of our position in Susquehanna, which we believe is in the sweet spot of the most prolific natural gas field in North America.

Our year-end reserves were 96 natural gas -- 96% natural gas, which is in line with last year's percentage. Our overall PUD reserve percentage decreased slightly to 40%. We continue to be fairly conservative in our reserve bookings, recognizing a modest 0.7 offset PUD locations for each of our proved developed wells in the Marcellus.

On our guidance for '13, we have reaffirmed our equivalent production growth range of 35% to 50%, and adjusted our liquids growth range to 35% to 50%, which reflects our capital allocation towards liquids.

The midpoint of our guidance for '13 implies 3 consecutive years of 40%-plus equivalent production growth, which is especially impressive, considering we expect to spend within cash flow based on our budgeted commodity price of $3.50 for natural gas and $90 per barrel of oil. Capital and cost guidance for the year remains unchanged.

We did do a little additional hedging towards the end of -- since the end of the year. We added 10 contracts to our '13 hedging program. All of those 10 contracts have floors that are above our budgeted number. And we added 5 contracts to our 2014 program. All of these were zero-cost collars. You can get the further details on our website.

Now let's move in to the specific areas, starting with the Marcellus. During the fourth quarter, we achieved a new milestone, with a 24-hour production rate exceeding 1 Bcf of gross production per day. This record was made possible by accelerating the turning in line of some wells that were scheduled for the first quarter of '13. We're able to move that up. And not only do we turn them all in line sooner, but we certainly saw outstanding performance from these wells.

During the fourth quarter, we turned in line 30 horizontal wells, which included 12 wells that were turned in line in the first half of December. Of these 30 wells, they had an average of 16.7 frac stages per well, 24-hour IP production rates of 20.1 million cubic foot a day and an impressive 30-day average production rate of 16.6 million cubic foot a day. Of note, in addition to the production highlights in our press release, 1 well we've had has reached 7 Bcf of cumulative production in 523 days. That is our fastest well to 7 Bcf to date. Just this week, we hit a new milestone for the field, reaching 500 Bcf in gross cumulative production from just 189 horizontal wells and a small contribution from several vertical wells.

With the acceleration of completions into December of '12, it created a 1 Bcf opportunity, and accomplishment production in the first portion of the years will be fairly flat as we coordinate new infrastructure with completion operations. We effectively accelerated over 100 stages into the fourth quarter. We completed a total of 871 frac stages during the fourth quarter and added additional -- added an additional drilling rig in December, giving us a total of 5 horizontal rigs in operation now. And we plan on drilling 85 wells in our 2013 program. We currently have 405 stages completing, cleaning up or waiting to be turned in line, along with an additional 282 stages waiting to be completed.

On the comment on the Marcellus infrastructure, we continue to see good progress on infrastructure program by our midstream partner, Williams is scheduled -- is on schedule with the right of ways, the permitting, construction and all the aspects of continuing on an ongoing infrastructure buildout for '13. Specifically, nearly all right of ways have been acquired and the vast majority of the gathering permits are in hand for our '13 program.

Now let's move to the South region in the Eagle Ford. To date, we have drilled 41 wells in our Buckhorn area of the Eagle Ford. Well costs continue to come down, with an average well cost targeted in '13 in the $6 million to $7 million range. We continue to be pleased with results of our down-spacing program, with wells drilled approximately 400 feet apart. These wells have shown comparable production and EURs as other wells in the field. We recently drilled our longest lateral well to date in the Eagle Ford, which was 8,200 feet. The well will be completed with a 28-stage frac job, and that treatment is scheduled in March.

Comments on the Pearsall. The drilling of the planned 15 gross wells for '13 is underway with 3 drilling rigs. Currently, 4 wells are completed or waiting on completion, and 5 wells are producing at this time.

The 30-day average production for the rates of 4 of the wells that have produced for at least 30 days so far is 631 Bcfe per day. The oil and gas ratio depends on the location of the wells moving in the north-south direction with an average ratio of 56% oil and 44% gas. As we are still in the early stages of this play, the region continues its work to refine the placement of the laterals in a very thick zone, and we're trying to optimize the completion techniques out there. Our objective is obvious, moving forward, is to reduce our completed well cost and continue to show improvements with our average production rates.

In our Marmaton area, we have reached -- we have 24 operated wells in production. The 2 drilling rigs are currently operating area -- in the area. The average initial production rate for all operated wells drilled in the fourth quarter was 562 BOE per day, which is approximately 90% oil. While we're very early in the extended lateral program, with only 3 wells on production at this time, we are very pleased with the early operations. These extended laterals average approximately 9,500 feet, and we're stimulating the wells with 30 frac stages. The average EUR, again, early time, we're seeing, is increased by 60% to 70% over the shorter laterals of 4,500 feet. The additional cost for the extended lateral is approximately 30% over the cost of the shorter laterals. In these wells, we see an extended cleanup period, with increasing production during this cleanup period prior to leveling off to a normal decline. We presently have 8 additional extended laterals planned for our '13 program.

In summary, 2012 was another outstanding year for Cabot, and we fully expect our momentum to carry into 2013. We're currently looking for ways to enhance and maximize shareholder value. And we know Cabot is very well positioned for another year of industry-leading production and reserve growth at best-in-class cost.

Laura, that completes my comments, and I'm most happy to open it up for questions.

Question-and-Answer Session

Operator

[Operator Instructions] And our first question is from Bob Brackett of Bernstein Research.

Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division

I have a question on running room in the Marcellus. Can you remind us of sort of drilling locations, down spacing, where your thinking is on that right now?

Dan O. Dinges

Well, so far, we're still in the process of capturing primary term acreage. Our spacing, where we do have wells close together, is 1,000 feet at this time. And it's our plan once we get to pad development drilling that we'll test down-space opportunities in the lower Marcellus. We have staggered a couple of wells in between 2 Lower Marcellus wells and the Upper Marcellus. And that staggered distance between those wells is 500 feet. We've seen good results in those particular wells. We have a couple of hundred thousand locations -- a couple of hundred thousand acres in the Marcellus. And we have at least 3,000 locations out in front of us.

Operator

And the next question is from Charles Meade of Johnson Rice.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

This first question I have is just sort of a qualitative one. Dan, I'm wondering if you and your team are surprised by some of these wells when they come online with their productivity, as I think a lot of people on the call are. Is this the kind of thing where you're still amazed when you see these reports come across your desk or is this -- or have you -- is this just what you expect at this point?

Dan O. Dinges

Well, Charles, you can see our financial metrics and our operating metrics that we're able to produce. And it's certainly a direct result of the -- of what we're seeing coming out of our particular area of the Marcellus. When we started this program, and we drilled our -- started our -- spud our first well up there in '05 and we moved it on into '06, we thought we would be in high cotton if we had a 4 Bcf well up there. As we progressed and as we continue to see our performance stay in a narrow range on a per well basis. Certainly we have very, very good wells and we have wells that are below the average obviously. But each tweaking we do, whether it's in how we're spacing the frac stages, for example, in '12, going from 250-foot spacing in our frac stages down to 200-foot spacing in our frac stages, we think we have enhanced our line a little bit by doing that.

Our costs continue to come down, so the addition of those several additional stages on a particular lateral length is not -- it's not a problem. And overall, that has enhanced our rate of return. But the production levels and the way that these wells perform on its natural decline I think have impressed not only Cabot, but I think it's impressed everybody that has taking a look at it. We use Miller and Lents as our third-party engineering firm. And Miller and Lents is in full support of our bookings. In fact, this year, in a discrepancy between outside engineering and internal engineering, we had less than 2% discrepancy in our reserve bookings, which as all can imagine is a very, very low delta between outside third-party engineering and internal engineers. We continue to be impressed. A long-winded answer. I am -- look at these wells and I've looked at a couple of the wells that we had brought on not that long ago. Couple of wells producing over 60, 70 million cubic foot a day, a well, shale well, producing over 40 million cubic foot a day, continues that 30-day average over 35 million cubic foot a day. I had 20 years in the offshore, and I would have taken that well offshore any day of the week.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

Right, right. Well, I appreciate that long-winded answer. I didn't think it was at all. It's great additional color. And if I could, just one follow-up, on the Pearsall. I know that you guys are going to be doing a lot of science there. But I was hoping you might add a little color on what the dimensions are of your experiments this year. Is it going to be kind of traversing northwest to southeast? Is it going to be more in what part of the zones, at what horizon you're completing in or is it the frac design or all of the above?

Dan O. Dinges

Yes, Charles, it's all of the above. And our layout of our program with this being an exportation play like it is, we were not certain without production where we were in the maturity window. We know, moving north to south, we have about a 20-mile range north to south. And we're seeing that transition within that geographic area. We have a very thick section in the Pearsall. Matt and his guys have landed the wells in a stratigraphic different spot in probably 8 or 10 of the wells that we have drilled so far. We have tried various different frac techniques that would allow us to, one, get all of our frac stages away and not screen out prematurely the spacing of those frac stages, where we put our ports in each particular frac stages being worked on and tweaked with Matt's group right now. So you can imagine that if we're landing in different spots and we're trying to frac different ways in different spots, if you look at the -- trying to get all of the iterations in 1 well and the data points together, it takes a lot of wells to be able to get all the data points and try to find the most cost-effective and efficient way of frac-ing these wells, so that's the experiment we're in right now.

Operator

And next we have a question from Brian Singer of Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

Can you just talk to where Marcellus production is currently? I think I heard you say kind of flattish trajectory during the first half. I just wanted a little bit more color if that's from current levels versus fourth quarter average levels and whether you're planning on completing wells during the first half.

Dan O. Dinges

Yes, we are -- right now, our current production is right at the gross Bcf in the Marcellus. We have -- and I'll pitch the ball to Jeff to just briefly talk about the infrastructure in a second. But we will be bringing on wells and getting them tied in. But as far as us being able to go beyond the Bcf, we're going to be somewhat limited with the completion of the infrastructure to see the full effect of that. But I'll let Jeff kind of bring it up to speed on where we are on the -- and Williams is on the infrastructure.

Jeffrey W. Hutton

We accelerated some wells into the fourth quarter, and that was due to Williams being able to get some permits, and actually, they're running several crews on the construction side of the business. So in conjunction with that, we also have some additional compressor stations that are scheduled for later in the year. We've talked about a central compressor station, which is now kind of a May, June event that will add some takeaway to the picture. And then we have additional units planned kind of late third quarter, early fourth quarter, which will also kind of enhance our overall position out there.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great. And then speaking with the transportation theme here, when you just think longer term, are you still seeing interest from consumers to use their firm transport capacity? Or when you think about longer term, are you looking for additional Cabot purchase from transport beyond Constitution?

Jeffrey W. Hutton

Well, currently, we have approximately 300,000, there in our own firm, so about 700,000 is using our customers' firm. And that seems to work very well. We have a number of long-term contracts using our customers' firm transport, so that also helps us. As you know, in 2 years, we'll pick up another 500,000 a day on Constitution. We've also participated on a project with Millennium and Columbia called the East Expansion. That's going to add another 50,000 a day in about 2.5 years. And so we're constantly evaluating our position there. The Leidy Southeast Expansion on Transco, we're able to get a long-term sale using Piedmont's firm transportation position on that expansion. So it's an ongoing effort and we -- everyday, we're exploring new ways to move gas.

Operator

And the next question is from Michael Hall of Baird.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

I guess, first, I just wanted to talk a little bit about your thoughts around capital allocation as I kind of look at your funding profile going forward to start throwing off some good free cash next year, it looks like. And just curious on your thoughts on what you might do with that if you're somewhat limited by infrastructure, where does that cash get allocated? And you talked about shareholder value enhancement. Is there any thoughts of returning any of that to shareholders or is that all plowed back in the ground? Just curious how you're thinking about that.

Dan O. Dinges

Well, we put together a 5-year model. We've gone over that 5-year model with our board. We've used modest commodity prices. And when I say modest commodity prices, it means below strip pricing to put our program and 5-year plan together. And as we see it, we are going to generate a significant level of free cash and growth in reserves and production throughout that period. On near-term capital allocation, when you look at our program this year, we do look like we'll generate a little bit of positive cash going into '14. Certainly, we'll generate a little bit more positive cash. One of the things that we would do with some of the positive cash generated from our drilling and producing operation is to spend, I don't know, $75 million to $100 million of it in participation with and construction of our Constitution Pipeline. We have 25% of that pipeline that is commissioned -- due to commission in March of 2015. As Jeff just mentioned, we have 0.5 Bcf a day net to Cabot to move through that pipeline. And as we have gone around, Scott and I have visited across the table with a number of our investors, that is a common question, what we're going to do with the cash that we'll be spending off. We're fully conscious of demand or value destruction by just going out and spending the cash because we have it in the bank. We have a unique position on -- with the Marcellus, and we know that we could be dilutive to a shareholder if we went out and just spent money on a project that doesn't compete with the amount of capital we allocate to the Marcellus and the return that we get from that. But you can think out ahead and you can look out there in the space what people do with the free cash. Options would be increased dividends, we could also place a special dividend out there to shareholders, we could look at share buybacks, we could also run sensitivities, which we have, and aggressive acceleration of our operations with that free cash also. So we're cognizant, we're thinking about it. We had a board meetings Wednesday and Thursday. That is a discussion in the -- inside the boardroom, and more to come on that, Michael.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

That's helpful. Appreciate it .If you had to kind of force rank those options that you just laid out, what's the kind of current thinking on that?

Dan O. Dinges

I'll let Scott -- obviously, with the -- with this 5-year model we have and looking at the amount of free cash we have and debt paydown that we can do, Scott just walks around the office with a big smile. I'll let him answer it.

Scott C. Schroeder

Clearly, Michael, what Dan laid out, the #1 priority is our investment of that excess, would be our obligation to fund Constitution. The second probably most efficient use of those dollars is a way of looking at the combination of leading into Constitution's coming online, what can you -- could you accelerate in the Marcellus. And then, third would be dividends of one form or another. So if you -- that would kind of be the top 3.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Okay. That's helpful. And then one more if I may. Just curious, and sorry if I've missed this. But what's the kind of planned lateral -- average lateral length in 2013 in the Marcellus program and average stages drilled on those wells or completed on those wells?

Dan O. Dinges

Well, the -- yes, Michael, the plan for '13 is probably going in at being slightly more than the '12 program, but I would think in the similar range. And the number of stages will probably go up, average number of stages will probably go up slightly because the majority of our '13 program is going to have the 200-foot spacing versus a mixed bag on the distance between frac stages in our '12 program.

Operator

And the next question is from Biju Perincheril of Jefferies.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Dan, on the 41 producing locations that you booked last year, can you talk about how many of those are completed using the tighter frac spacing and what EUR those wells were booked at?

Dan O. Dinges

15. 15 of the 41 were used with the tighter spacing.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Okay. And can you talk about what the average EUR for those wells are versus sort of the [indiscernible]

Dan O. Dinges

Yes, the average EUR for those 15 wells was slightly higher than the 13.9 Bcf on the other wells.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Got it. Okay. And then the well that you talked about, I think, that was the 35-stage well. Can you give us some color on what was the lateral length and cost on that one and...

Dan O. Dinges

Okay. The lateral length, I have -- let me ask Steve here. What was it? 6,875 was the lateral length, and the cost was I think between $7 million, $7.5 million.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Okay. So it did, I mean -- it sounds like that's -- you clearly have seen some productivity improvement efficiency gains as you look with that long laterals and more stages. So just what are the opportunities to further increase the lateral length and more stages in your operations there?

Dan O. Dinges

Well, I think the opportunity to continue to extend our laterals is valid. We had a good success on the all-stage fracs, even the 2 [ph] stages on that completion. Once you get out to the 30-stage frac, you get concerned about completely being able to get away what your design frac stage might be, and -- but we were pleased. We do anticipate that our average lateral length will continue to creep up.

Keep in mind right now that we don't have development drilling going on that, we're on these particular pad sites, and we're capturing our primary term acreage, and we're drilling 2, maybe 3 wells per pad. Also, keep in mind that there is not forced pooling in Pennsylvania. And if we still have holdouts out there, as much as we would try to buy and lease very, very small tracks of acreage, that it does affect some of the lateral lengths that we would drill, certainly, we would prefer drilling in a uniform fashion out there. But it's just not quite as possible because of the current regulations in Pennsylvania. But with that said, our objective is to drill most -- the most cost-effective or return effective wells that we can design out there.

Operator

And our next question comes from Pearce Hammond of Simmons & Company.

Pearce W. Hammond - Simmons & Company International, Research Division

I apologize if I missed this, but what are your current well costs in the Marcellus right now, and then where do you think that could trend to by year end?

Dan O. Dinges

Well, since we've gone a little bit longer laterals and a few more stages, we're kind of between the $6 million, $6.8 million range. And again, from an efficiency standpoint, ongoing across-the-board trying to continue to drive cost out of the drilling complete side.

Pearce W. Hammond - Simmons & Company International, Research Division

Great. And then, Dan, for your acreage in Susquehanna County, are there any other targeted horizons beside the Lower Marcellus, Upper Marcellus and the Pearsall?

Dan O. Dinges

We think there could be. But our focus and concentration right now is exclusively on the Marcellus.

Pearce W. Hammond - Simmons & Company International, Research Division

Great. And then the last one for me, any update on the Utica?

Dan O. Dinges

Well, the Utica is, again, operated by Range. I would imagine, I don't know, I think they're close to coming out in release. And typically, as we do with non-operated positions, we defer to the operator. I can't say that we've been pleased with results to the extent of what we saw in the thickness side. I think, the -- in the maturation portion of the well, we're pleased with what we've seen and expect it to be in the liquids-rich area. And I think we're there. We certainly saw decent pressures in the well and got a little production out of it. Moving forward, certainly, we'll conduct more activities moving forward. I know Range is a great operator and very talented. They're going to be looking at where we land the well, how we complete the wells going forward. And just like our comments in the Pearsall, they're going to be trying to sort through how to maximize the results. So I've got all the confidence in the world in Range.

Operator

And our next question is from Matt Portillo of Tudor, Pickering, Holt.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

You guys have put up some pretty fantastic results in Dimock and Springville. And I was just curious, as we think about the 10 to 15 Bcf type curves that you guys have experienced over the last year or so, I'm just curious how we should think about that in terms of the prospectivity over your entire acreage position in Susquehanna. And I guess, as we think about the delineation going forward, how should we think about kind of appraisal of the rest of your acreage position over the next few years?

Dan O. Dinges

Well, we -- the data points that we've given, Matt, outside of where the majority of our drilling has taken place so far. If you move from our area where the majority of the infrastructure is built to where we have been producing for the most part, we've moved east 7 miles from closest production to the Zick area. That's right along the Tennessee 300 line. We've put a compressor there. We drilled 5 wells from that pad site. And the wells in that particular area are equivalent to or right at our 2012 program. We have gone another 9 miles to the east of that, really to the far eastern edge of our acreage. We don't have pipeline out there that's going to be coming in, in probably the second, maybe early third quarter -- or third quarter, maybe early fourth quarter, all the way out to the Eastern portion of our acreage out there. But we have drilled wells and completed those, flowed those wells back, and looked at the characteristics of those flowbacks. What we saw in the flowback and the pressures we saw and how rapid those wells unloaded, they were extremely consistent with what we've seen in our other areas. We've moved to the northeast, slightly to the northeast of our area, the majority of our drilling. We had a pad site there where we had -- we drilled 4 wells, and we were able to get an early look at the production and have brought those wells on line. And those wells on line fall right on our curve also for the average results we've seen on our '12 program.

So we continue to step out. We do have data points out there that we feel comfortable de-risking our acreage, de-risking in a manner consistent with the results that we were seeing, and we feel good about a vast majority of our acreage being able to yield consistent results.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

So just to clarify there, is it fair to say that as you move into the neighboring townships to the East, you guys are pretty comfortable with kind of a 10-plus Bcf type curve for those assets from what you've seen so far?

Dan O. Dinges

Yes.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Perfect. And then as we think about your Marcellus asset today, I was just curious, within that 5-year plan that you've laid out, could you give us a little color on how we should think about kind of plateau rig count given the infrastructure takeaway you have at the moment? Or where we should think that rig count trends to over time?

Dan O. Dinges

Yes. And certainly, Scott, through his group, managed the build out of that 5-year plan. Scott, you want to...

Scott C. Schroeder

Yes. Matt, what we did is we haven't seen a plateau either in the production over the next 5 years or in the rig count. We did a -- as Dan alluded to in an earlier question, that we didn't -- we weren't aggressive on the underlying commodity price deck. So it was a fairly conservative price deck, capping out at $4 per Mcf. And so we've kind of ramped up gradually, 1 to 6, then to 7, 8. And we, I think, in 2017, we were at 9 or 10. So again, we didn't go real aggressive on the rig count for the Marcellus.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Great. And then, I guess just final question for me, looking at your asset base today with the Eagle Ford, Marmaton and Pearsall, obviously, kind of given what we've seen from a return perspective in the Marcellus, those assets may struggle a bit to compete for capital. I was curious if those are potentially up for divestment at some point. And would that be something that you'd be interested in? And I know you've done the Pearsall JV, but just curious how you guys are thinking about those on an incremental basis.

Dan O. Dinges

Well, you can tell by our capital allocation, we have basically $1 billion program in '13. We're allocating 70% to the Marcellus. We're allocating the rest of it to liquids in the areas that you've identified in the South. And we're balancing our program. We don't have any illusions of us trying to make a transition from a natural gas company to a liquids company. But we do think, with the assets that we have in this -- in the liquids windows, that we can yield very, very good returns. And if you have the commodity price and differential that we see today, and I'm talking about the $90-or-so oil prices, that though they do not compete with our Marcellus returns, they nevertheless are competitive returns for the cost of capital and yielding good returns for shareholders. They -- and moving forward, and if you looked at how we want to ramp up and when we get the infrastructure build out of the Marcellus and we continue to add production there, we're going to have enough free cash to do that. But you did not hear us say that we're going to have hear us say that we're going to ramp up and continue dumping a lot of money into our liquids areas. We're going to keep a modest amount of capital going in that particular area. We'll capture the primary term acreage we have in areas that do yield very good returns, and we'll continue to grow our liquids production in that vein.

But because of the free cash, it's -- we understand the balance between putting together a program that's going to yield the outstanding returns we are yielding and what it would do if we allocated significant cash to lower return assets. So I don't know if I answered you directly, but our liquids assets are good assets. We have talked about in the past that we JV some of those assets. If we felt like there was a strong use of capital, we certainly have that flexibility within our current balance sheet and with our $1 billion program. But if we felt like that if we wanted to capture some additional cash, certainly, it would be those assets that we would sell or JV to accomplish that.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

I apologize. Just one follow-up question if you're comfortable answering it. Just as I think about the 5-year program, is there any color you guys would like to give in terms of rough range on production for the Marcellus kind of on that rig program you've talked about?

Dan O. Dinges

It's -- I'll answer it by, it's large. And Scott wants to say something.

Scott C. Schroeder

Again, we give guidance kind 1 year at a time, 18 months at the most, just because there's lot of varying factors. But I'll echo Dan's comment, the numbers get very large.

Operator

And our next question comes from Gil Yang of DISCERN.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

For the PUD upward revision, it's going to 9 Bcf per well, are those 9 Bcf wells booked at the 200-foot frac density?

Dan O. Dinges

Well, the -- they're booked at -- assuming a number of stages, we don't really get that granular on booking PUDs, I'm saying that they're 200-foot spaced frac stages. But we do reduce -- to arrive at that, we have a reduced number of stages to the PUDs, and that's 12 to 13 stages.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

Okay. So I guess what I'm trying to get at, was the upward revision of PUDs driven by performance of neighboring PDP or was it a change in the number of frac, fracs in those wells?

Dan O. Dinges

It was really a -- we try to -- when we booked year end reserves, and Steve Lindeman, again, is responsible for our bookings and managing our reserve book, what we try to do is balance our entire report and make it simple for our shareholders to read through. And one of the things that we try to do is stay fairly consistent with our percentage of PUD booking. We don't try to fluctuate that number. We also remain what I would say is very conservative on our PUD booking in the Marcellus. As I mentioned, for each location, PDP location that we have out there, we only have 0.7 locations on the PUD side. So we're very, very conservative in that regard. But that allows us to continue to balance the overall PUD number on our year-end bookings.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

Okay. And related to the overall -- the tighter frac spacing opportunity, do you think -- do you have any indication yet whether or not the decline, the type curve decline rate is the same? Or is there a potential for a steeper decline rate once you get out maybe a few years with the tighter spacing?

Dan O. Dinges

Yes, well, I'll make a brief comment, then I'll let Steve Lindeman answer it. But we're comfortable on our curve fit in what we're seeing. But, Steve, do I'll let you add.

Steven W. Lindeman

Yes, Gil, what we're seeing is they are performing very, very comparable to our other further spaced stages. We've got 6 wells that have been on line now for between 6 to 8 months. So we got quite a bit of production information on those, and they've recovered somewhere between, let's say, 17% -- 15% to 18% of their EUR. So we've got pretty good information, and they are performing very similarly to the other wells.

Operator

And our next question comes from Doug Leggate of Bank of America Merrill Lynch.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

I've got a couple of questions, Dan. I guess I'm trying to pull together a lot of the comments you've made on the 2012 type curve. Is it a little simplistic, but could you help us understand what proportion of your acreage at this point do you think is capable of replicating those results and how are you prioritizing your rig allocation towards those high EUR wells at this point?

Dan O. Dinges

I'll let Steve answer the latter part of that, but I'll answer the first part. As I indicated on an earlier question, I think Matt asked, we have a -- drilled a large geographic area with producing results in our acreage position. The farthest step outs that we have moved to the east, at the Zick location, which is 7 miles from our big area of drilling and where we laid our infrastructure. And those wells are performing very well. And I think they've been on over 200, maybe pushing a year is how long those wells have been on. And we've then moved 9 miles further to the east and have flowback wells there that show consistency with what we've seen in our areas of -- for example, 13.9 Bcf 2012 average that we've given. We don't have infrastructure out there to produce those wells for an extended period of time, but the information we've seen is good. So percentage-wise, it would be a SWAG number and certainly, 60%, 70% is a SWAG number at this stage.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

That was I was looking for. And on the rigs?

Dan O. Dinges

Yes. And I'll let Steve answer that.

Steven W. Lindeman

And, Doug, just to elaborate a little bit more, in terms of decline, it's very impressive at how these wells performed very similarly per stage. And so when you look at the statistics across our area, it's very, very consistent. And so I think as Dan alluded to, we've got a lot of confidence moving out towards the east.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Okay. So I guess my follow-up is you're probably aware there's a fair number of acreage packages that seem to be coming in the market up in your areas. I'm just curious if you're showing an interest there. If you have any color as to whether there are any opportunities that are meaningfully out to what is already clearly a perfect position.

Dan O. Dinges

Yes, Doug. We're aware of the acreage packages that are coming on the market. We have a geologic model that we initiated our leasing on, and we have continued to refine through the -- not only the data that we have as operated data but also industry data throughout the area. And our position that we do have and where our acreage is, is there for a very good reason, which fits our geologic model. And we're entirely comfortable with our position in Susquehanna, where we -- where our current footprint is.

Operator

And next, we have a question from Chad Landry [ph] of Iberia Capital.

Unknown Analyst

Just had a quick question. On the timing of your new central compressor station, if you could kind of update us on that, and also kind of quantify what you think the uptick could be in terms of production on older Marcellus wells.

Dan O. Dinges

Okay. I'm going to let Jeff field that one, Chad.

Jeffrey W. Hutton

Chad, I think at this point, we pretty much have taken all the risk out of getting central up and running by midyear, or at least Williams has, with the receiving of their air-quality permit late last year. So right now, we just have a construction project. Everything is up there, and Williams is pushing forward to get everything going. In terms of line pressure impact, that's hard to engineer at this point and it's difficult to say what the extra 50 pounds or 100-pound reduction in the -- in certain parts of the field will do to the older wells. So I guess I'm going to avoid giving you an answer on that part of your question.

Operator

And the next question is from Robert Christensen of Buckingham Research Group.

Robert L. Christensen - The Buckingham Research Group Incorporated

Yes, let's look out to the future a little bit and maybe help us understand how you might be marketing your gas. Is there opportunities to sell it long-term to some of these big independent power plants that are in the region? And is there outlet, maybe on the East Coast, to export LNG facility that you're contemplating marketing to?

Jeffrey W. Hutton

Okay. That's a big question. We have seen market dynamics change a lot in just 4 years up there, of course. Currently, we do have a significant amount of our production that is sold out 5 years and even out 10 years. And of course, we have a 100,000 a day sale that begins in '15 that's out 15 years. And so we've continued to add to the base of long-term sales commitments. In terms of demand though, we've seen lots of interest, particularly when Constitution was announced from the power sector. They have been very interested in getting gas off the Iroquois Pipeline, the Tennessee 200 line, and that, of course, goes into the Boston area, and also the Canadian aspect of Constitution connecting to Iroquois and then moving on up to Canada. So we've been very encouraged by the interest from that perspective. On the LNG, we have taken out some capacity last year and early this year that will enable, right now, about 75,000 a day of our production to reach Cove Point. And so we have firm transport in place to -- and are staying on all the short lists for possibility of supplying a significant amount of gas to the export facility there. But overall, we see demand increasing, manufacturing, the demand increasing, new power plants coming on to full retirement aspect. So from a demand perspective, it looks really good in the Northeast.

Operator

And our next question is from Joseph Stewart of Citi.

Joseph Stewart - Citigroup Inc, Research Division

Most of my questions have been answered but I had one clarification. Dan, in response to a previous question, you noted that current well costs are running $6 million to $6.8 million. Is that based on an 18-frac stage well, or how many frac stages are you using there?

Dan O. Dinges

Well, the range is the result of how many -- a variable amount of frac stages, Joe. That's from a 3,500 to a 4,500-foot type of well, and however many frac stages we apply to that well. So I just kind of threw out a -- without having a specific number, I'm kind of throwing out a range on what I'm seeing on the AFEs and stuff coming across my desk.

Joseph Stewart - Citigroup Inc, Research Division

Got it, okay. And so we should assume the 200-feet per stage bill on that lateral?

Dan O. Dinges

Oh, yes, absolutely.

Operator

[Operator Instructions] I'm showing no further questions, I'd like to turn the conference back over to management for any closing remarks.

Dan O. Dinges

Thank you, Laura. I think the questions were very good. And we've had an opportunity to answer them all. We look forward to our '13 program and feel very confident that we're going to be able to produce outsized results by year-end '13. Appreciate it. Thanks, Laura.

Operator

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.

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