Dan O. Dinges - Chairman, Chief Executive Officer, President and Member of Executive Committee Scott C. Schroeder - Chief Financial Officer, Vice President and Treasurer Jeffrey W. Hutton - Vice President of Marketing James M. Reid - Vice President and Manager of South Region

Andrew Venker - Morgan Stanley, Research Division Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division Pearce W. Hammond - Simmons & Company International, Research Division Brian Singer - Goldman Sachs Group Inc., Research Division Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division Jeffrey Campbell - Tuohy Brothers Investment Research, Inc. Biju Z. Perincheril - Jefferies LLC, Research Division Gilbert K. Yang - DISCERN Investment Analytics, Inc Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division Gordon Douthat - Wells Fargo Securities, LLC, Research Division Robert L. Christensen - Canaccord Genuity, Research Division Zachary Berger Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

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

Thank you, Emily. Good morning, all, and thank you for joining us for this call. I have a number of members of the executive team with me today to assist in the Q&A session. Before we start, let me say the standard boilerplate and forward-looking statements included in the press release apply to my comments today. On the call today, we will plan to cover the following: our third quarter 2013 operating and financial results; an update on our operations in the Marcellus and Eagle Ford; and finally, an update on our guidance for 2013 and 2014, including our capital budget and operating plans for 2014. Before I go into details of these topics, let me start with the financial highlights from the quarter, which was, by the way, one of best quarters we have had. For the third quarter, we produced 107 Bcfe of total company net production or approximately 1.16 Bcfe per day, which is an increase of 61% over last year's comparable quarter and a 13% increase sequentially over the previous quarter. Liquids production increased 43% over last year's comparable quarter and 18% over last quarter, driven by 28% sequential increase in our Eagle Ford liquids volumes. Net income grew significantly during the quarter, increasing 91% over last year's comparable quarter. While net income, excluding select items, increased 73% over the same period. In the third quarter, we also continue to generate robust cash flow growth with discretionary cash flow and cash flow from operations, increasing 69% and 61%, respectively, over the last year's comparable quarter. Our third quarter unit cost of $2.97 per Mcfe were down 15% over last year's comparable quarter and down 4% relative to last quarter, continuing to demonstrate how our already industry-leading cost structure continues to trend lower. In fact, our cash…

[Operator Instructions] And our first question comes from Drew Venker of Morgan Stanley.

Penetrating on the buyback program, are you currently authorized to start buying back shares? And can you offer some more color on where that program can go?

I'll answer that, Drew. This is Scott Schroeder. We have had an outstanding buyback authorization for a longer period of time. With the splits and the adjustments in it, it is up to just under 10 million shares. Our blackout period will end today so -- and we're fully operational if we choose to go in and buy shares on weakness at various points in time. And it'll be up more after-the-fact kind of disclosure, where we just wanted to, in light of all the questions we had around free cash flow, in light of the weakness of the stock, we wanted to be more proactive in saying that we do have that as an arrow in our quiver, and we will use it when we see it appropriate.

Okay. And it looks like if we look ahead, you could be generating, I guess, more cash flow than I was thinking before, at least. Are you guys open to maybe looking at acquisitions or expanding into new areas where that's organic or where acquisition-based? Do you have any thoughts there?

Well, Drew, we have -- with our current capital guidance that we've given, we have several areas that have been included in that capital exposure that are exploratory in nature. And if, in fact, those are areas that yield returns that are competitive with our existing projects, we will consider expanding into those areas. At this time, we have also continued to pick up some acreage in the areas that we operate. And -- but we do not have plans and are not focused on buying a bolt-on in an area that we are not currently exposed to.

Okay. Lastly, just on well costs. I guess given that you're talking about longer laterals, bigger wells, overall, going forward, where do you see well cost going from here?

Well, the well cost, again, when you look at the average and you look at the nets that we have and 100% working interest wells, the increase on the drilling side is typically not that substantial because the drill rates and penetration rates are so robust. But the incremental ad that we have will be by virtue of more stages in those longer laterals. And in our pumping services, we are -- we have very good contracts on our pumping services, and the uptick will be a direct proportion to the incremental number of stages. So I would say probably anywhere from $250,000 to $500,000 on some of the expanded wells that we drill.

Okay. And thinking, maybe, where you are right now with well costs?

Well, on -- and we've gone to and we've still used, as we have highlighted in our discussion points in our presentation, our '14 Bcf well, for example, in the Marcellus is around this $6-plus million range. In the Eagle Ford, we have highlighted, and particularly in our press release with the most recent drilling that we've been able to do and particularly on, we're on a pad right now. We haven't gotten to TD, but we're drilling pad wells there with a walking rig. And we think, again, reiterating what I've said in the release, that we think we're going to be saving, just on the drilling side, $500,000 to $600,000 per well in the Eagle Ford. And we think we're going to get our well cost below the $7 million range.

Next question comes from Doug Leggate of Bank of America Merrill Lynch.

The 100% working interest wells this year, is that more of a high-griding exercise? Or what -- how sustainable is your drilling program at that level? And maybe you could help us with the average working interest across the 2 plays, currently.

Yes. It is a little bit of an aberration as we go into '14, and there is a couple of reasons for that. The couple of reasons that make the majority of impact is, one, through '13, we had a significant level of joint venture wells that we operated and we drilled in our joint venture with Osaka. So from a net perspective, we had a number of gross wells in there, but we didn't net out the higher percentage because of Osaka's interest. Additionally, by virtue of the sale of the Marmaton up in Oklahoma, we had a number of nonoperated wells up in the Marmaton that we participated in. And we also had on the operated wells, we also were anywhere from, say, 35% to 85% working interest in the operated wells. And that was one of the reasons why we elected to refocus into our core areas where we have blocked acreage and where we can have greater efficiencies at 100% operated wells going forward. We do anticipate that by virtue of, again, having to anomalous events, the JV in the Pearsall and the sale of the Marmaton, that we will have a much, much higher working interest percent on average than we have in the past.

Really helpful. And I guess so, that my follow-up would be in your prepared remarks, you talked about you expect in your capital review, your plan for next year and the year after. You expect longer laterals in sequentially '14 and -- well, '13 and '15 over '14, but also more stages per well, I guess. Can you just help us understand this? How much further do you think you can go in terms of improving the efficiencies of these individual wells? And I'll leave it at that.

Okay. It's a good question, Doug. And the industry, as a whole, has certainly been pushing the limits of extended laterals and reduced spacing on frac stages. Some other ideas being tried is increased profit per stage. I think it is true, we'll continue to tweak and try different ideas that would enhance the efficiencies. In our Eagle Ford operation, as an example, we had averaged 4,000 or 5,000-foot type laterals in a pad that we are currently on right now. We are going to average out to 9,000-foot on those particular Eagle Ford locations on that pad. How much further you get out is at least, in our sense right now beyond 9,000 feet, is going to be pushing it with current technology and current efficiencies to be able to assure yourself you're getting effective fracs at the tow stages. But nevertheless, as you can see going straight from 5,000 to 7,500 or 9,000, certainly, is a step further out in the Eagle Ford. In the Marcellus, we continue to extend our average lateral lengths in those particular wells. And we have some wells that we have planned for '14 that would allow us to put, say, place 40-or-so stages in a particular well. So we are extending them out further, but it's not going to be as aggressive of increase as you have seen in the past, by industry as a whole, I might add.

And the next question is from Charles Meade of Johnson Rice. Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: I was wondering, Dan, could you give us an idea on both the timeline of these long-lateral Eagle Ford wells that you're drilling, the timeline we should expect results on? And really, what kind of rates you're looking for out of those wells?

Yes. Charles, that's a good question. We have, again, on one of these pads we're on, we have drilled 6 of the top holes on a 6-well pad, and now we're going back and we're starting the laterals on that 6-well pad. As a placeholder, we had completed a 4-well pad. And we completed that 4-well pad that had a measured depth of 58,000 feet, and we completed it in 58 days. So pretty simple 1,000-foot average throughout 4 wells on a -- on that particular pad. So I don't know if that will hold true, Charles, as we get out even further with the lateral lengths. But that kind of gives you a benchmark to work with. Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: Got it. But just the key thing here though, is that you're batch drilling, and are you going to do a batch completion on that pad as well?

Yes, we will. Yes. And just one other quick point, Charles, on that. And that's the reason I kind of said, well, when we come out with the data, we will probably have something at our year-end call in February, we would hope, a little bit more color on results of these wells. But the 6-well pad is probably not going to be a great -- a lot of time on that particular pad site, but we should have some more color, certainly, on our year-end call. Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: Got it. It'll be a lot of oil when it does come at you. But before I...

And we -- we're working on... Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: Before I -- right. The other thing I wanted to ask, just to touch briefly on this Northeast differential issue, I looked up at one of the regional hubs out there, and there's actually been a dramatic or -- there's been a pretty quick tightening or narrowing of the basis just in the last week. And so I was wondering if you could -- we're about -- we're close to 1/3 of the way through the quarter, and I could just -- wondered if you can offer a few more thoughts on how it's looking for the last 2 months of the year.

Well -- and I'll let Jeff just add some brief color to it. But I will say this. I looked at it, and we had our board meetings, of course, yesterday and the day before, and we kind of glanced at it. One of the indices was up $0.72. Again, volatility is the name of the game. But -- and we ran through a lot of sensitivities, as I mentioned, in the little talk here. And we think it's going to be volatile. There is going to be times when we don't like the number, and there's going to be times that we can catch up. And through all that sensitivity, we feel like the range that we've given is supportive. And not only that, with the type of wells that we're drilling and the unit cost discounts that we're seeing, our return profile for this program is going to be significant. And in fact, if you back up a little ways and you take the noise out that's been most recently discussed in regard to the most recent past differentials, our returns are probably going to compete against returns that we had when we didn't have this differential noise. Yes, I'll let -- I think Jeff wants to make a comment also, Charles.

Yes, Charles, I'll get a little more specific with your question. The Leidy Line that you're speaking of has seen, I think, a great improvement just in the last week. Although I will say it's been improving in the last 6 weeks little by little, as Tennessee has improved as well and demand has improved in some of the other pipes. I think on the Leidy Line, the volume of gas that reaches that pipeline is pretty much at its max. So the pipe is full. What's been missing up there has been the demand. And now the demand piece has shown up, we're going to see improved price in there. And in fact, I think yesterday's gas day was maybe $0.05 under NYMEX, so a big improvement. And then on Tennessee, with that pipeline opening up on November 1 with the new capacity in the Bcf a day, since we'd want them -- about 300 went west, about 700 went east, the transportation opportunities and the path has opened up. And we've seen a big improvement there. Not quite like Transco's Leidy Line, but we expect to see, as winter progresses, more flattening of that basis as well.

And our next question is from Pearce Hammond of Simmons & Company. Pearce W. Hammond - Simmons & Company International, Research Division: Were there any one-offs that impacted Q3 Marcellus differentials like pipeline maintenance, things like that, that are worth highlighting, which may not be repeatable, say, next year?

Yes, I'm going to flip that right off to Jeff, Pearce.

Okay. Yes, particularly in the third quarter, we had, I wouldn't call it as bad as a perfect storm scenario, but we have a number of scenarios that changed the dynamics of pricing, particularly on Tennessee. They had some -- obviously, they had construction all summer to facilitate new capacity coming on November 1. So that was hammering some of the areas that normally did not see reduction in capacity. We also had folks taking gas off Tennessee trying to get to other locations that were already full, and so that also intensified the problem. We had some -- the weather, I don't want to harp on how mild the weather was, but the lack of power-gen on that particular pipeline is very sensitive to demand regarding whether, both winter and summer. So we have that concern at the same point. There was obviously a little bit of new production that came on, that also added to that scenario. But overall, we think that with this new capacity and normal weather conditions, that will return to a more historic-type basis. Pearce W. Hammond - Simmons & Company International, Research Division: And then, Dan, what are your thoughts about de-risking other horizons on your Marcellus acreage? I know you've done some completions in the past on the Purcell, but what about something like in Onondaga?

Well, Pearce, one of the things -- one of the processes and procedures that we're going to be able to get to in our '14 program is that the examples of pad drilling that we've been discussing. And pad drilling means getting to the 6, 8, 10 wells per pad, maybe 12, 14 wells per pad. But the opportunity at that time will allow us to try multiple ideas on that particular pad that would be -- allow us to look at analogous similar geology, and the information and gather -- and data points we get from that similar geology will allow us to maybe make a little bit better interpretation of what the results are telling us. So in some of the things that we're going to try to accomplish, which are going to be reduced spacing in the Lower Marcellus. We'll have also the Purcell test. We'll have the Upper Marcellus test. And we will look at the -- any other ideas that we have in additional rocks that might be something for the future. So that's the time we're going to do that, Pearce. Yes. And I would say towards the end of '14, we would be able to give you some additional color on all those points.

Our next question is from Brian Singer of Goldman Sachs.

When we look at your end markets for gas, I think you had said about 65% of this year's contracts are linked to Henry Hub. Can you talk to what that number is for next year? And how is the relationship to Henry Hub of next year's contracts compared with this year's?

Okay. I'll let Jeff give you a brief executive summary on that.

Yes, Brian, the 65% for 2013, we're going to look at growing that number for 2014 just because of the production growth. And so what I'm trying to say is most of the next round of contracts pertaining to the production growth will be tied to NYMEX-based contracts. So it's pretty much as simple as that. As far as what's going on in '14 compared to '13, we -- as we've talked about before, we took great lengths to put together all of our portfolio of contracts and transactions to be able to supply you with this range for pricing going forward. If you tried to compare that to pricing in 2013, I know we were relatively flat in NYMEX in quarter 1 and quarter 2. And then you saw the results for quarter 3, and we're probably pretty close to our guidance for 4. So you can kind of work the numbers from there.

Okay. Just to make sure I understood the early part of your response, when you talk about adding new volumes to increase the number, are you increasing the percent above 65%? Or are you keeping the percent reported at the same soon-to-be and just adding contracts given your growth?

The percent will grow.

Okay. And then when we think about the key milestones to meeting the midpoint of the 2014 guidance, can you just walk us through key items that you see on the critical path regionally within Susquehanna County? I guess, one would assume if you get to your -- if you get the rig count ramped up on schedule then those items on a critical path will be more from a midstream perspective.

Are you talking about our production volume, Brian?

Yes. So for us to have confidence that you are at versus above versus below, or for you to have confidence that you are trending at versus above versus below your 2014 volume guidance, what do you see as items on a critical path as you go forward through 2014?

One, on the operational side, I don't see anything that is going to deter us from achieving the volume rates that we have forecast. Operationally, we have the -- one, we have a significant level of wells that we're going to roll into '14 and a significant number of stages in those wells that we roll into '14. And with the level of drilling that we have between now and then and the addition of the seventh rig, I think we are going to be able to meet or exceed the guidance that we've given with our operations program. The length of laterals, the number of stages and our ability to secure the pumping fleets up there are all within our reach, and I see no issues in regard to that. The 30% to 50% guidance we gave, as I've kind of talked through in the teleconference write-up, we are -- we're looking at the -- all the sensitivities on us pulling off, even throughout the full year, us pulling off production that would be representative of some of our day gas. So even in light of that, we have a significant opportunity to meet or exceed our production guidance. So I'm -- any key milestones, it's really going to be conducting our operations as effectively and efficiently as we have in the last few years.

So basically, there's nothing on the critical path from a midstream perspective? That's all in place, and so it is executing on the upstream and watching the markets to make sure that demand is there? Or are there midstream -- key midstream items to think about?

There's not anything in the midstream that is going to be a critical path item for us to be able to achieve our higher rates that we forecast. In fact, at the end of '14, we will have in the form of compression, dehydration and our measurement capacity, 3.4 Bcf available to us.

And our next question is from Bob Brackett of Bernstein. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: A couple of questions. One, you mentioned the quality of the rocks early on as a kind of a commanding advantage. Have you guys ever benchmarked through the Northeast gate [ph] what advantage the rocks have versus what your own proprietary completions have?

Say that again. I'm sorry, Bob, I... Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: Can you separate how good the rocks are from how good your completion strategies are up in the Marcellus?

Okay. I appreciate that. Well, the feedback we get from the North region personnel is it's all their completion technique. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: That would be expected.

But to quantify that, we do things in our completion operations up there. We were first movers. We discovered the Northeast Pennsylvania, Marcellus, and we have developed it with the first drilling up there in that particular area. And we have a core group, extremely talented individuals that have paid attention to it and have done their tweaking and evaluation. And so I certainly think what we do has some bearing on it. But I also think that the Marcellus that we drilled in our particular area is uniquely thick compared to the rest of the Marcellus you see across the entire state and into West Virginia. The maturity of it is at a perfect maturity that allows it to have a very low amount of connate water frac-ing. And viability of that allows it to be extensively fractured with the fracs that we put on it. And I think the recoveries that we get up, in place reserves as a result of that, and not having any water in the system and any concerns about permeability issues down the road, we are in the absolute best spot you can find, as far as reservoir quality. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: And a follow-up, you talked about differentials being flat to minus $0.40 off of Henry Hub. What's your view for Henry hub for next year?

We haven't looked at the Henry Hub, except to say that, on average, we are going to be between the, say, $3.80 and $4.

Our next question is from Jeffrey Campbell of Tuohy Brothers Investment.

I just wanted to ask one question to each regarding Eagle Ford and the Marcellus. I'll go with the Marcellus first. It looks like your average production per stage is spot-on with the wells you highlighted in the second quarter. And -- but in the second quarter, you gave us some locational color with regard to the wells being north and northeast of Zick. I was wondering if you could give us some kind of indications of what the locations of the 4 pads highlighted in the third quarter are.

They were at -- they were scattered throughout our areas. We had a pad site to the northeast, not just east, but to the northeast. We had a pad site to the south and southwest, and so they were scattered throughout our area. And by the way, they were in 4 different townships.

Okay, good. That's helpful. And with regard to the Eagle Ford, about the time you guys were at our conference in August, you had reported an 8,000-foot Eagle Ford well that had basically no decline over a 3-month period. And I was just wondering if there's any follow-on data with regard to that well, and if you've seen any kind of similar type of behavior in the wells that you've drilled subsequently.

Yes, I'll let Matt Reid respond to that and kind of give you maybe what we produce to date, and it's still performing well.

Right. That's our Pickens B16 well, had a lateral length of about 8,200 feet, 30 stages. That well's produced 125,000 barrels in about 200 days. It still continues to produce an equivalent rate of about 600 barrels equivalent per day. So it's been fairly flat, great producer, good EUR. So -- and the wells we're drilling off the current pad will be similar in length to the Pickens well.

Our next question is from Biju Perincheril of Jefferies.

A couple of questions. The wells that you highlighted in the Marcellus earlier today, and looks like even compared to some of the reduced cluster spacing wells that you had talked about earlier, looks like there's an improvement. Other than the longer laterals, are there other things you're doing on the completion front that is still diving improvement in productivity?

Well, we have got our spacing down. Some of our -- a small portion of our '12 program had the 200-foot stages spacing. And all of our 13 wells and our wells going forward are going to have that phasing -- spacing. And when you look at what we do on the completion side, again, back to the comment I made on, I think, to Jeffrey was that -- or Bob, the guys up there have continuously tried different techniques and processes on our completions and we have a good database right now and we try different things all the time.

Okay. And then as far as northeast demand is concerned, I think you guys have been looking pretty close look at it being a longer-range plan. Anything you can share in terms of new market opportunities for pipelines or incremental demand?

Yes. I'll chuck that to Jeff, Biju.

Yes. Biju, we have -- it's an ongoing process for us as we look at different options getting out of Susquehanna County. I think you'll -- if you follow the open seasons, by the compliance, particularly the nonbonding open seasons, you see a lot of projects around drawing boards that get gas out in Northeast PA, particularly to the Carolinas, to the mid-Atlantic area and additional pipe. More in, obviously, the Constitution and into New York here in November. But I think the other thing that's a little bit missing from the equation is all the new projects in Southwest PA that will move gas most likely to Canada and obviously back on racks. And all the backhaul projects and pipe reversals that are going on there will also influence the Northeast production and probably obtaining more market share of the projects I mentioned previously. So it's ongoing. We have a number of ideas and it's -- we hope to expand on that in the next few months.

And in the next few months, is it likely that we could hear it from kind of like Cabot-sponsored pipeline like the Constitution? Is that -- or is that on the industry projects that you're referring to?

Yes. Probably bad choice of words, the next few months. These projects take a long time to develop. And I think the pipelines are putting them together as we speak. We're trying to make decisions on which projects are best for us. And then if it's more than one, just what share of those projects that we participate in. So it's ongoing. There's more than a dozen that would benefit us directly. And so we're in an evaluation stage at this point.

Our next question is from Gil Yang of DISCERN.

Just a couple of questions sort of following up on some of the other questions. The role that you were talking about for going into 2014, are you in any way because of the curtailments that you had voluntarily placed on, are there more wells sort of waiting to be turned on than you would have expected? And does that lead you to go into 2014 a little hotter than you would have originally planned and sorts of make it easier for you to grow?

Gil, it's a good question. We have certainly capacity. And in fact, I think today's rate is probably a rate that is higher than maybe we've seen. But the result is that we do have -- we do have volumes that are upcoming with some robust completions that we expect that we have risked, if you will, on the production profile we've included in our forecast.

Okay. The risk via the curtailment issues.

Right. Not versus productivity, just reframe the timing of when they would come in. And Gil, this is Scott. Just based on the simple math, we do have 6 rigs running in the Marcellus now. So just by the nature of that activity, we're going to have a higher number of completions going into the next year than we had last year.

Sure. Right, okay. And then with regard to completions, have you given much thought to -- or have you also been tweaking lateral spacings? Or do you think you're pretty much optimized in terms of the distance between laterals or any Chevroning of the laterals within that formation?

Yes. Well, on the -- are you talking about the frac stage spacing?

No, no. Well, obviously, you've gotten on to the 200-foot spacing within the frac -- for the frac stage length. I'm just talking about the spacing between the laterals that you're drilling.

Oh, okay. Yes, all right. Yes, Gil. Well, that is a -- like I've mentioned before, once we do get on some pads, we will be looking at reduced spacing. We will and, in fact, we have drilled a couple of wells that have gone down to 800-foot, and we will continue to look at what we think is a very optimal spacing. But that is the plan to continue to reduce from the 1,000 feet we have right now to something less.

You want to say -- can you say what happened to the 800-foot spacing?

Still too early.

Our next question is from Jack Aydin of KeyBanc.

Looking at the -- is any of those 4 pads that you had in the quarter, any of them is Reilly Pad? Or Reilly Pad was not included in those?

No, we don't have the pipeline yet hooked up out there, Jack. I know we're still waiting on that. And the anticipation is that, that we would be able to get it hooked up this quarter, and we still believe that to be the case. But again, we did -- these are pads that are outside of the area where the majority of our drilling has taken place. And as I mentioned, they're in 4 different townships.

And second question, do you have another opportunities to acquire additional acreage in Susquehanna? Is there anything available to add on bolt-on in your acreage in Susquehanna? Or did you do any purchases in this quarter?

Well, the -- some of the purchases that we've done has just been by virtue of some of the small tracks picking up the lessors that have, or the mineral owners that have desired to wait until there is going to be a well drilled near them and in the event they lease on them. And we have picked up some acreage in that regard throughout the year along those lines. There, as far as a bolt-on piece of acreage that we could buy, we're not negotiating any at this time.

Some clarification, Dan. You mentioned you placed 1 B in 2013 at a fixed, and about 900 in Bs from April 2014 to the end of the year. Is that fixed, firm or what? What kind -- could you clarify it a little bit for me what you mean by that?

Yes, yes. Jack, I'll let Jeff on.

Okay, Jack. What we're telling the world here is that we have a Bcf a day of gas already placed for the winter period. That's November through March of this year and first quarter of 2014. When we say placed, we mean we have that wet gas under contracts and similar-type contracts that we always have with splits between different indices, but primarily based on NYMEX. And then that we have approximately 900,000 a day for the summer period, that's April through October. It's already under contract. So those are all firm sales. And for the most part, we've utilized the majority of our firm transportation with those sales. So we think we're in pretty good shape with a large majority of our gas already under contract.

Our next question is from Gordon Douthat of Wells Fargo.

Question on the lateral lengths for this year. So at 200-foot spacing, I think you mentioned in your prepared comments, you've added about 3 to 4 frac stages this year. So does that get you about 47,000, 48,000-foot lateral?

Yes, that's good math.

Not 47,000 feet.

I'm sorry, 4,700 feet.

There you go.

Scott will always get the numbers right. He's good with numbers.

And then I believe you had some of those on since 2012. I'm just trying to get a sense of what type of production history you need on those longer laterals with the tighter frac spacing in order to feel comfortable increasing those EURs.

Well, on the flowbacks and what we see early-stage time on the wells that we have brought on, we feel very comfortable that we're going to have increases in those wells based on what we've seen through our other wells. And the fit on the production curve is going to tell us fairly quickly that we can expect a better EUR. There's nothing that we see right now that's going to deter us from our position that EURs will be higher in '13 than they were in '12.

Okay. And then you mentioned that probably with the reserve report, on the 2013 reserve report, you'd discuss that further. Is that something that you'd talk about in February?

Yes.

Okay. And then to what extent is that incorporated in 2013 production guidance and then also 2014 production guidance?

Well, we kind of look at what the production curve fit is for our normal wells out there, and we use that curve fit and roll it all the way through the year to come up with our production profile. So from that sense, the EUR is applicable when used in what we forecast. But I'm not sure I'm answering your question though, Gordon.

I'm just trying to get a sense of what -- is there upside to the numbers? I know you've given some fairly wide ranges next year, but what extent do you feel like -- I know production has been pretty strong, but what extent there might be more upside?

Well, I think the guidance we've given is robust. I think the guidance we've given is going to be in the top of the class. And we've kind of made a statement in the past, Gordon, that if we wanted to grow by putting in, say, we put in another spot crew in for 4 months and we average a number of stages that we complete in a day is, say, 6, well, I can assure you that if that's what we wanted to do, that we could really increase our production profile. So I'm comfortable with the range that we're in, and I think you've seen in our past guidance that we have been probably a company that has underpromised and overdelivered, and we're not going to change our methodology.

Our next question is from Robert Christensen of Canaccord Genuity.

Can you just please -- and some of my question was previously answered. But as the next pipeline, I'm looking at all the projects that the pipelines are putting up. How are the negotiations going with these pipelines in terms of getting a deal done? Are you pleased? And could such a thing happen where you'd have a big write-out or 2 out of the area by '15, get some steel in the ground in '14 if you get behind 1 or 2 of these things? And then basically, permanently and these worries over basis differentials, give us a sense on how it's going.

Yes. Well, I'll start and I'll pass it to Jeff. But, Robert, when you look at the space and you look at differentials, there's going to be a number of things that between now and '17, and I know that's not the term that you've talked about, but between now and '17, now and '16, now and '15, that will make a difference in the takeaway capacity. In particular, up in our area in the northeast. But if you look at some of the things that are going on away from us and you look at, maybe, the intangible benefits, those are going to have an impact on us also. There was a question earlier in the Q&A session, talked about are there anomalous events that have created a burden on differentials in this period. Well, if you go back and you look at the southwest part of the state, there was a period of time that there was a purchase of a lot of the Rex gas to be able to move gas and comingle with the volumes in the market that exasperated, if you will, the problem. And some of that was a result of some dominion issues that they had and maintenance things that they had down there. That had a direct impact during the third quarter that we don't think is going to be another recurring event. We think that there is a move of foot to reverse Rex and take southwest gas in the west direction. And we think there's projects that are going to be going down and alleviating some gas that is currently flowing east, to flow in other directions from other areas. We think Gulf Coast gas is going to be finding different homes versus flowing on the long-haul pipes up into the east. But as far as pipeline negotiations, I'll turn it over to Jeff. And he can, maybe, make more detailed sense out of what I just said.

I'm not trying to invade the propriety of the discussion you may have, I'm just trying to get a sense of how much -- how well the discussions are going to, maybe, take gas to Atlanta for all intents and purposes.

Okay. Yes, it's certainly dynamic times. It's actually kind of fun at this point to be involved in so many projects and also be in the position to offer up a substantial quantity of gas dedicated to some of these projects. So we are involved in practically every single one of them in some way, shape or form. We think smaller positions and some make more sense to us. But we also think the region, in general, needs a larger stroll out of it. And there's obviously several very large diameter pipes planned to leave the area. You mentioned Atlanta. Obviously, there's discussions around that particular city. There is in Birmingham, Alabama, all the way from Susquehanna County to Birmingham on the Atlantic Sunrise project that we're very interested in. First, negotiations themselves. Obviously, you want to be involved in a project that you think will work and has constructibility aspects to it. And also, we want to make sure that the pipelines that we participate in are kind of slam dunk in terms of FERC approvals, those sorts of things. So we work very hard to that end to make sure those things happen. I don't think you'll see those, any of the projects that are on the drawing board right now who have progressed to almost to the prefiling stage of FERC be built in 2014. But I do think in 2014 with the projects that are coming on in November of this year, that we'll have spare capacity through that period of time. That's why we're pretty confident that we're not going to see some of the issues that plagued us in the third quarter. So with the current spare capacity coming on combined with 2015 projects that we know about, and I'll put Constitution out there for just a moment and try to give you a timeline for how these projects get built, we came up with a concept, the Constitution in November 2011. So it's been 2 years. But the good news there is it's just 17 months away. And in the pipeline world, that's not far. And it's going to open up a whole new world for us and others. And so these projects are kind of a 3, a 3.5-year horizon on completions. But keeping in mind, the Bcf that's coming on November was started about 3 years ago, and here we are. So they're ongoing. And again, I think we're in a very good position to be able to be a shipper on a number of projects.

Our next question is from Zach Berger of Conatus Capital.

My questions have been answered.

And the next question is from Matt Portillo of TPH. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just a quick question for me. In terms of in the Marcellus, you mentioned the longer lateral lengths over the next year. So I was wondering if you could give us some context in relation to your acreage position and how you think about kind of the longer term in terms of the lateral length you're able to achieve. Is that closer to 5,000, to 6000-foot in lateral length? Or just how should we think about kind of your drilling plans on a go-forward basis?

We will be able to achieve over 5,000-foot laterals. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Perfect. And then just in regards to your drilling plans next year, you mentioned a very robust 180 to 190 wells. I was wondering how your inventory levels will fluctuate around that, and if you guys plan to maintain a similar inventory, potentially below down sort of inventory you have, or maybe see a little bit of build. Just trying to get some context around that.

So we'll have -- both areas will have a significant inventories out in front of us, the 400-foot spacing in the Eagle Ford. We have over 500 locations, and we have 3,000 locations in the Marcellus. And we're stacked in multiyear inventory based on the number of wells that we project to drill in '14. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: I'm sorry. Just -- I apologize. To clarify that, just in regards to the drilling program, you mentioned 180 to 190 wells. How should that compare to the completion side of it? So are you planning to kind of have a one-to-one drill to completion? Or will we expect the inventory to build a little bit next year in the Marcellus?

No. We're going to have 7 rigs running. So when you drill several wells from a pad, and you're -- and you have more rigs, say, 7 versus 6, we would expect that, just by nature, you're going to have some drilling activity happening on now 7 pads versus 6, that's going to have wells that will be in the near-term backlog and in the Q waiting to be completed. So yes, we think that will build a little bit. And we also think that, obviously, the number of completed wells and completed stages will be increased also. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Great. And then last question for me on the Eagle Ford. I was just hoping to get an update on how you're thinking about spacing at this point in terms of the spacing between the wellbores and potentially tighter spacing on a go-forward basis?

Well, there's a lot of different pilot programs being conducted in the Eagle Ford, different areas. Of course, each area is unique with its own unique geology. But we have 400-foot spacing and results from 400-foot spacing that we're comfortable with. We will try wells slightly closer and see if there's merit to that. But certainly, at this stage, we're very comfortable with the data we have at 400 feet.

This concludes our question-and-answer session. I'd like to turn the conference back over to Mr. Dinges for any closing remarks.

Okay. Thank you, Emily. Appreciate the questions. I hope that we were able to clarify how we arrived at our projections in our guidance and the supporting data that we used to determine that. And I think the focus has been, for the last 6 or 8 weeks, intently on the differentials. I think if you combined what our program offers and the continuing efficiencies that we deliver in our program, not only with the longer laterals and reduced cost, but our unit costs are going to continue to go down. And I think the bottom line and the measure of what you might be able to accomplish and yield return for the shareholders, I think, should be measured on what you can deliver in your report card at the end of the year. And with what we've seen in '13 so far, and what we see coming in the fourth quarter of '13, I think we will be able to deliver a report card at the end of the year that will be very robust and indicate what type of capital efficiency our program yields. Additionally, with what we see in '14 and the enhancements and improvements we see through our program in '14, I am very confident that we'll be able to deliver an equally impressive report card at the end of '14. Thanks for your attention. Goodbye.

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