Good morning, and welcome to the Cabot Oil and Gas fourth quarter 2012 earnings conference call. All participants will be in listen only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on your touchtone phone. To withdraw your question, please press star then two. Please note, this event is being recorded. I would now like to turn the conference over to Dan Dinges. Please go ahead, sir.
Thank you, Laura. 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 Technology, Matt Reid, who runs our South region, 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 2013, 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. I think these are worth repeating.
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 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. Now let's move to the financial operational results. For the full year of 2012, 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 2011, as all operating expense categories decreased on a per unit basis in 2012, except for our transportation and gathering in taxes and other income. 2012 was a milestone year for the company operationally as we achieved one BCF per day of gross Marcellus production and one BCFE of total company net production during December. For the full year, we continue 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 20%, 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 of 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 of 7.5 BCF to nine 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, 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 2013, we have reaffirmed our equivalent production growth range of 35%-50% and adjusted our liquids growth range to 35%-50%, which reflects our capital allocation towards liquids. The midpoint of our guide for 2013 implies three consecutive years of 40%+ 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 a little additional hedging since the end of the year. We added 10 contracts to our 2013 hedging program. All of those 10 contracts have floors that are above our budgeted number, and we added five 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 into the specific areas, starting with the Marcellus. During the fourth quarter, we achieved a new milestone with a 24-hour production rate exceeding one 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 2013. We were able to move that up, and not only did we turn them 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 feet a day, and an impressive 30-day average production rate of 16.6 million cubic feet a day.
Of note, in addition to the production highlights in our press release, one 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 2012, that created the 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 371 frac stages during the fourth quarter and added an additional drilling rig in December, giving us a total of 5 horizontal rigs in operation now. 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 on schedule with the right of ways, the permitting, construction, and all the aspects of continuing on an ongoing infrastructure build-out for 2013. Specifically, nearly all right of ways have been acquired and the vast majority of the gathering permits are in hand for our 2013 program. Let's move to the south region in the Eagle Ford.
To date, we have drilled 41 wells in our Buckhorn area. The Eagle Ford well costs continue to come down with an average well cost targeted in 2013 in the $6 million-$7 million range. We continue to be pleased with the results of our downspacing 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 2013 is underway with 3 drilling rigs. Currently, 4 wells are completed or waiting on completion. 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 stage 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 24 operated wells in production. The 2 drilling rigs are currently operating 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 three wells on production at this time, we are very pleased with the early operations. These extended laterals average approximately 9,500 feet. We're stimulating the wells with 30 frack stages. The average EUR, again, early time, we're seeing is increased by 60%-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 eight additional extended laterals planned for our 2013 program.
In summary, 2012 was another outstanding year for Cabot. We fully expect our momentum to carry into 2013. We're currently looking for ways to enhance and maximize shareholder value. We know Cabot is very well positioned for another year of industry-leading production and reserve growth at best-in-class costs. Laura, that completes my comments. I'm more than happy to open it up to questions.
Certainly. At this time, if you would like to ask a question, please press star then one on your touch-tone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star then two. At this time, we'll pause momentarily to assemble our roster. Our first question is from Bob Brackett of Bernstein Research.
I had a question on running room in the Marcellus. Can you remind us of sort of drilling locations, downspacing, where your thinking is on that right now?
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. It is our plan once we get to pad development drilling that we'll test downspace opportunities in the lower Marcellus. We have staggered a couple of wells in between two lower Marcellus wells in the upper Marcellus, and that staggered distance between those wells is 500 feet, and 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.
Thank you.
The next question is from Charles Meade of Johnson Rice.
Good morning, gentlemen. 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 the 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 just what you expect at this point?
Well, Charles, you can see our financial metrics and our operating metrics that we're able to produce. It's certainly a direct result of what we're seeing coming out of our particular area of the Marcellus. When we started this program and we spot our first well up there in 2005, and we moved it on into 2006, 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 good wells. We have wells that are below the average, obviously.
Each tweaking we do, whether it's in how we're spacing the frack stages, for example, in 2012, going from 250-foot spacing in our frack stages down to 200-foot spacing in our frack stages, we think we have enhanced our life a little bit by doing that. Our costs continue to come down. The addition of those several additional stages on a particular lateral length is not a problem. Overall, that has enhanced our rate of return. 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 taken a look at it. We use Miller and Lents, Ltd. as our third-party engineering firm. Miller and Lents, Ltd. 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 low delta between outside third-party engineering and internal engineers. We continue to be impressed. Long-winded answer. I am. I look at these wells. I've looked at a couple of the wells that we had brought on not that long ago. A couple of wells producing over 60, 70 million cubic foot a day. A Shell 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. I would've taken that well offshore any day of the week.
Right. Well, no, I appreciate that long-winded answer. I didn't think it was at all. It's great additional color. 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. I was hoping you might add a little color on what the dimensions are of your experiments this year. Is it going to be traversing northwest to southeast? Is it going to be more in what part of the zones, what horizon you're completing in? Is it the frack design or all of the above?
Charles, it's all of the above. Our layout of our program, with this being an exploitation 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 eight or 10 of the wells that we have drilled so far. We have tried various different frack techniques that would allow us to, one, get all of our frack stages away and not screen out prematurely. The spacing of those frack stages, where we put our ports in each particular frack stage is being worked on and tweaked with Matt's group right now.
You can imagine that if we're landing in different spots and we're trying to frack different ways in different spots, if you look at the trying to get all of the iterations in one 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 fracking these wells. That's the experiment we're in right now.
Great. Thanks a lot, guys.
Thank you.
Next we have a question from Brian Singer of Goldman Sachs.
Thank you. Good morning.
Hi, Brian.
Can you just talk to where Marcellus production is currently? I think I heard you say flatish trajectory during the first half, and 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.
Yeah. Right now our current production is right at the gross BCF in the Marcellus. I'll pitch the ball to Jeff to just briefly talk about the infrastructure here in a second. We will be bringing on wells and getting them tied in. 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 effects of that. I'll let Jeff bring you up to speed on where we are, and Williams is on the infrastructure.
Good morning, Brian. 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. In conjunction with that, we also have some additional compressor stations that are scheduled for later in the year. We've talked about Central Compressor Station, which is now a May, June event. That'll add some takeaway to the picture. Then we have some additional units planned late third quarter, early fourth quarter, which will also enhance our overall position up there.
Great. Thanks. Then sticking with the transportation theme here, when you just think longer term, are you still seeing interest from consumers to use their firm transport capacity? When you think about longer term, are you looking for additional Cabot purchase firm transport beyond Constitution?
Well, currently we have approximately 300,000 a day of our own firm, so about 700,000 is using our customer's firm, and that seems to work very well. We have a number of long-term contracts using our customer's firm transport, so that also helps us. As you know, in two years, we'll pick up another 500,000 a day on Constitution. We've also participated in a project with Millennium and Columbia called the East Expansion. That's going to add another 50,000 a day in about two and a half years. So we're constantly evaluating our position there. The Leidy Southeast expansion on Transco, we were able to get a long-term sale using Piedmont's firm transportation position on that expansion. It's an ongoing effort, and every day we're exploring new ways to move gas.
Great. Thank you.
The next question is from Michael Hall of Baird.
Thanks. Good morning.
Good morning, Michael.
I guess first I just wanted to talk a little bit about thoughts around capital allocation as I look at funding profile going forward, start throwing off some good free cash next year looks like. Just curious on your thoughts of what you might do with that if you're somewhat limited by infrastructure, where does that cash get allocated? You talked about shareholder value enhancement. Are there any thoughts of returning any of that to shareholder, or is that all plowed back in the ground? Just curious how you're thinking about that.
We've put together a five-year model. We've gone over that five-year model with our board. We've used modest commodity prices. When I say modest commodity prices, we use below strip pricing to put our program and five-year plan together. 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 nearer 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 2014. 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-$100 million of it in participation with and construction of our Constitution Pipeline.
We have 25% of that pipeline that is due to commission in March of 2015. As Jeff just mentioned, we have a half a BCF a day net to Cabot to move through that pipeline. 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 spinning 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 with the Marcellus, 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.
You can think out ahead, 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, an aggressive acceleration of our operations with that free cash also. We're cognizant. We're thinking about it. We had board meetings Wednesday and Thursday. That is a discussion inside the boardroom, more to come on that, Michael.
That's helpful. I appreciate it. If you had to force rank those options that you just laid out, what's the current thinking on that?
I'll let Scott. Obviously, with this five-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 that.
Clearly, Michael, what Dan laid out, the number 1 priority is our investment. Of that excess would be our obligation to fund Constitution.
Second, probably most efficient use of that dollars is a way, looking at the combination of leading into Constitution, coming online, what could you accelerate in the Marcellus? Third would be dividends of one form or another. That would be the top three.
That's helpful. One more, if I may. Just curious, and sorry if I've missed this, but what's the planned average lateral length in 2013 in the Marcellus program, and average stages drilled on those wells or completed on those wells?
Yeah, Michael. The plan for 2013 is probably going to end up being slightly more than the well program, I would think in a similar range. The number of stages will probably go up. Average number of stages will probably go up slightly because the majority of our 2013 program is going to have the 200-foot spacing versus a mixed bag on the distance between frack stages in our 2012 program.
Okay, great. That's helpful. Appreciate it. Congrats again.
Thanks.
The next question is from Biju Perincheril of Jefferies.
Hi, good morning.
Biju.
Dan, on the 41 producing locations that you booked last year, can you talk about how many of those are completed using the tighter frack spacing and what EUR those wells were booked at?
Fifteen. Fifteen of the 41 were used with the tighter spacing.
Okay. can you talk about what the average EUR for those wells are versus?
Yeah, the average EUR for those 15 wells was slightly higher than the 13.9 Bcf on the other wells.
Got it. Okay. Then, the well that you talked about, I think that was a 35-stage well. Can you give us some color on what was the lateral length and cost on that one?
Okay. The lateral length, let me ask Steve here. What was it? 6,875 was the lateral length. The cost was, I think, between $7 million-$7.5 million.
Okay. It sounds like that, you clearly are seeing some productivity improvement, efficiency gains as you look with that long laterals and more stages. I guess, what are the opportunities to further increase lateral length and more stages in your operations there?
Well, I think the opportunity to continue to extend our laterals is valid. We had good success on the off-stage fracs, even the toe 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. 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 two, maybe three wells per pad.
Also, keep in mind that there's 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 tracts 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. With that said, our objective is to drill the most cost-effective or return-effective wells that we can design up there.
Got it. That's very helpful. Thanks.
Our next question comes from Pearce Hammond of Simmons & Company.
Good morning.
Morning, Pearce.
I apologize if I missed this, what are your current well costs in the Marcellus right now, where do you think they could trend to by year-end?
Well, since we've gone a little bit longer laterals and a few more stages, we're between the six, $6.8 million range.
Per section.
From an efficiency standpoint, ongoing across the board, trying to continue to drive cost out of the drill and complete side.
Great. Then Dan, for your acreage in Susquehanna County, are there any other targeted horizons beside the Lower Marcellus, Upper Marcellus, and the Purcell?
We think there could be, our focus and concentration right now is exclusively on the Marcellus.
Great. The last one for me, any update on the Utica?
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. Typically, as we do with non-operated positions, we defer to the operator. I can say that we've been pleased with results to the extent of what we saw in the thickness side. I think 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, and certainly we'll conduct more activities moving forward, I know Range is a great operator and very talented, and 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. I've got all the confidence in the world in Range.
Thank you, Dan.
Thank you, Pearce.
Our next question is from Matt Portillo of Tudor, Pickering, Holt.
Good morning.
Hey, Matt.
You guys have put up some pretty fantastic results in Dimock and Springville. I was just curious, as we think about the 10-15 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. I guess as we think about the delineation going forward, how should we think about appraisal of the rest of your acreage position over the next few years?
Well, 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 and where we have been producing, for the most part, we've moved east seven miles from closest production to the ZIC area. That's right along the Tennessee 300 Line. We put a compressor there. The wells in that particular area are equivalent to or right at our 2012 program. We have gone another nine 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 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. We have drilled wells and completed those, flowed those wells back, and looked at the characteristics of those flow backs. What we saw in the flow back 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 of the majority of our drilling.
We had a pad site there where we drilled four wells. We were able to get an early look at the production and have brought those wells online. Those wells online fall right on our curve also, for the average results we've seen in our 2012 program. 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're seeing. We feel good about a vast majority of our acreage being able to yield consistent results.
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 a 10 plus BCF type curve for those assets from what you've seen so far?
Yes.
Perfect. as we think about your Marcellus asset today, I was just curious, within that five-year plan that you laid out, could you give us a little color on how we should think about plateau rig count, given the infrastructure takeaway you have at the moment, or where we should think that rig count trends to over time?
Certainly, Scott, through his group, managed the build-out of that five-year plan. Scott, you want to?
Matt, what we did is we haven't seen a plateau either in the production over the next five years nor in the rig count. As Dan alluded to in an earlier question That we weren't aggressive on the underlying commodity price deck. it was a fairly conservative price deck, capping out at $4 per MCF. we ramped up gradually, went to six, then to seven, eight, and I think in 2017, we were at nine or 10. again, we didn't go very real aggressive on the rig count for the Marcellus.
Great. I guess just final question from me. Looking at your asset base today with the Eagle Ford, Marmaton, and Pearsall, obviously, 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. Would that be something that you'd be interested in? I know you've done the Pearsall JV, but just curious how you guys are thinking about those on a incremental basis.
You can tell by our capital allocation, we have basically a billion-dollar program in 2013. We're allocating 70% to the Marcellus. We're allocating the rest of it to liquids in the areas that you identified in the South. 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. We do think with the assets that we have in the liquids windows, that we can yield very good returns. 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 are nevertheless our competitive returns for the cost of capital and yielding good returns for shareholders.
In moving forward, if you looked at how we want to ramp up and when we get infrastructure build out the Marcellus, we continue to add production there, we're going to have enough free cash to do that. You did not 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, we'll continue to grow our liquids production in that vein. Because of the free cash, 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.
I don't know if I answered you directly, our liquids assets are good assets. We have talked about in the past, do 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 billion-dollar program. If we felt like that we wanted to capture some additional cash, certainly it would be those assets that we would sell or JV to accomplish that.
I apologize, just one follow-up question, if you're comfortable answering it. Just as I think about the five-year program, is there any color you guys would like to give in terms of a rough range on production for the Marcellus on that rig program you've talked about?
I'll answer it by it's large, and Scott wants to say something.
No. Again, we give guidance one year at a time, 18 months at the most, just because there's a lot of varying factors. I'll echo Dan's comment. The numbers get very large.
Understood. Thank you very much.
Thanks, Matt.
Our next question comes from Gil Yang of Discern.
Hey, Dan. Hey, Scott.
Hey, Gil.
For the PUD upward revisions going to 9 BCFs per well, are those 9 BCFs wells PUDs booked at the 200-foot frac density?
Well, they're booked at assuming a number of stages. We don't really get that granular on booking PUDs, on saying that they're 200-foot spaced frac stages. To arrive at that, we have a reduced number of stages to the PUDs, and that's 12 to 13 stages.
Okay. I guess what I was trying to get at was the upward revision in the PUDs driven by performance of the neighboring PDP, or was it a change in the number of fracs in those wells?
When we book 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. 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, PD location that we have out there, we only have 0.7 locations on the PUD side. We're very conservative in that regard, but that allows us to continue to balance the overall PUD number on our year-end bookings.
Okay. Then in relation to the overall tighter frac spacing opportunity, do you have any indication yet whether or not the decline, the type curve decline rate is the same, or is there potential for a steeper decline rate once you get out maybe a few years with the tighter spacing?
Yeah. Well, I'll make a brief comment then I'll let Steve Lindeman answer it. We're comfortable on our curve fit and what we're seeing. Steve, I'll let you add.
Yeah, Gil, what we're seeing is they are performing very comparable to our other further spaced stages. We've got six wells that have been online now for between six to eight months, we've got quite a bit of production information on those. They've recovered somewhere between, let's say, 15%-18% of their EUR. We've got pretty good information, they are performing very similarly to the other wells.
All right, great. Thank you very much.
Thanks, Gil.
Our next question comes from Doug Leggate of Bank of America Merrill Lynch.
Thanks. Good morning, everybody. Thanks for taking my questions.
Morning.
I got a couple of questions, Dan, I guess, to try and pull together a lot of the comments you've made on the 2012 type curve. It may be a little simplistic, but could you help us understand what proportion of your acreage at this point you think is capable of replicating those results? How are you prioritizing your rig allocation towards those high EUR wells at this point?
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 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 ZIC location, which is seven miles from our big area of drilling and where we laid our infrastructure. 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. We've then moved nine 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. The information we've seen is good.
I guess what I was saying there.
Percentage wise, it'd be a swag number and certainly 60%, 70% is a swag number at this stage.
That's what I was looking for. Thanks, Dan, on the rigs?
Yeah. I'll let Steve answer that.
Doug, just to elaborate a little more, in terms of decline, it's very impressive at how these wells perform very similarly per stage. When you look at the statistics across our areas, it's very consistent. I think, as Dan alluded to, we've got a lot of confidence moving out towards the east.
Okay, thanks. I guess my follow-up is, you're probably aware there's a fair number of acreage packages that seem to be coming on the market up in your areas. I'm just curious if you're showing any interest there, if you have any color as to whether there are any opportunities that might meaningfully add to what is already clearly a terrific position.
Yeah, 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 not only the data that we have and as operated data, but also industry data throughout the area. Our position that we do have and where our acreage is there for a very good reason, which fits our geologic model, and we're entirely comfortable with our position in Susquehanna, where our current footprint is.
Okay. I'll leave it there. Thanks, Dan.
Thank you.
Next we have a question from Chad Landry of Iberia Capital.
Hey, guys. How you doing?
Chad.
Just had a quick question on the timing of your new Central Compressor Station. If you could update us on that and also quantify what you think the uptick could be in terms of production on the older Marcellus wells.
Okay. I'm going to let Jeff field that one, Chad.
Okay, Chad. I think at this point, we've pretty much taken all the risk out of getting Central up and running by mid-year, or at least Williams has, with the receiving of their air quality permit late last year. Right now we just have a construction project. Everything is up there. 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 an extra 50 pounds or 100-pound reduction in certain parts of the field will do to the older wells. I guess I'm going to avoid giving you an answer on that part of your question.
Okay, thank you.
Thanks, Chad.
The next question is from Robert Christensen of Buckingham Research Group.
Yeah, let's look out into the future a little bit and maybe help us understand how you might be marketing gases there. Opportunities to sell it long-term to some of these big independent power plants that are in the region, is there an outlet maybe on the East Coast to export LNG facility that you're contemplating marketing to? Thank you.
Okay. That's a big question. We have seen market dynamics change a lot in just four years up there, of course. Currently, we do have a significant amount of our production that is sold out five years and even out to 10 years. We have 100,000-a-day sale that begins in 2015, that's out 15 years. 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 into Canada. 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. We have firm transport in place to and are staying on all the shortlists for possibility of supplying a significant amount of gas to the export facility there. Overall, we see demand increasing manufacturing, demand increasing new power plants coming on the coal retirement aspect. From a demand perspective, it looks really good in the Northeast.
Very good. Thanks for confirming all that. Thank you.
Thank you, Robert.
Our next question is from Joseph Stewart of Citi.
Good morning, everybody. Congratulations on another solid quarter.
Thanks, Joseph.
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-$6.8 million. Is that based on an 18-frac stage well, or how many frac stages are you using there?
Well, the range is a result of a variable amount of frac stages, Joe. That's from a 3,500-foot to a 4,500-foot type of well and however many frac stages we apply to that well. I just, without having a specific number, I'm throwing out a range of what I'm seeing on the AFEs and stuff coming across my desk.
Got it. Okay. We should assume the 200 feet per stage, though, on the-
Oh, yes, absolutely.
Yep. Okay, great. That's all I had, guys. Thank you so much.
Thanks, Joe.
If you'd like to ask a question, please press star then one at this time. Showing no further questions, I'd like to turn the conference back over to management for any closing remarks.
Well, thank you, Laura. I think the questions were very good, and we had an opportunity to answer them all. We look forward to our 2013 program and feel very confident that we're going to be able to produce outsized results by year-end 2013. Appreciate it. Thanks, Laura.
The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.