Coterra Energy Inc. (CTRA) Q2 2012 Earnings Report, Transcript and Summary

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

Pearce W. Hammond - Simmons & Company International, Research Division Biju Z. Perincheril - Jefferies & Company, Inc., Research Division Brian Singer - Goldman Sachs Group Inc., Research Division Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division Joseph Stewart - Citigroup Inc, Research Division Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division Robert L. Christensen - The Buckingham Research Group Incorporated

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

Thank you, Emily. I appreciate everybody joining us this morning for this second quarter conference call. With me today is Scott Schroeder; Jeff Hutton, our VP of Marketing; Steve Lindeman, our VP of Engineering and Technology; Matt Reid, handles our South Region; and Todd Liebl, VP of Land and Business Development. Before I start, as usual, the boilerplate standard language that we have is forward-looking statements included in the press release do apply to my comments today. Excuse me. At this time, we have many things to cover, and I'm going to expand on the press releases that were issued last night. I'll briefly cover the financials in the second quarter. We'll update the '12 guidance, including a capital discussion, as well as a preliminary review of our 2013 plan, and the recent successes that we had with drill bit, and I'll follow that with a discussion of our operations. Before I go into the details on these topics, I'd like to start with just a brief list of the highlights that we've seen in this last quarter. Cabot grew production 40% over the comparable quarter of last year, including 37% growth in natural gas and a 96% growth in liquids. Second quarter production was up 5% quarter-over-quarter, and this is even after the impact of unscheduled maintenance and the delays we've talked about as attached to our Marcellus gathering lines. We have brought online a 2-well pad that together the wells have produced 2 Bcf in 39 days, and they are still producing right at 59, 60 million cubic foot a day. The initial down space test in our Buckhorn area in the Eagle Ford and the zipper fracs, which were the first we'd tried out there, have proven to be successful. Along with our down space initiatives in…

[Operator Instructions] And our first question will come from Pearce Hammond of Simmons. Pearce W. Hammond - Simmons & Company International, Research Division: I know it's early, and I appreciate the look at the '13 guidance, but was curious for that '13 capital guidance. What is the rig forecast by region behind that guidance?

We're going to be in 5 or 6 rigs in the Marmaton and we're going to -- I mean -- excuse me, in the Marcellus. And we're going to have a couple of rigs in the Eagle Ford, and we'll probably have 3 rigs in the Purcell, and we'll have the 2 rigs in the Marmaton. Pearce W. Hammond - Simmons & Company International, Research Division: Perfect. And then in the new guidance slide you state it's been...

Yes, let me just also mention, there might be 1 or 2 more wells drilled in areas that we'll talk about once we get better definition of those. Pearce W. Hammond - Simmons & Company International, Research Division: Okay. And then in the new guidance slide, you state that the new 2012 CapEx guidance is $775 million to $825 million, and that's net of proceeds from asset sales in the Purcell JV. What is the CapEx if you include the proceeds from the Purcell JV and any asset sales? So we just add the $125 million from the first Purcell JV on top of that?

Yes, Pierce, that's exactly right. So it'd be $900 million to $950 million.

Our next question comes Biju Perincheril of Jefferies. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: A couple of questions. First, looking at the '13 guidance. Can you -- is there any contribution -- or how much contribution have you baked in from Utica and Purcell in those numbers?

In the '13 guidance? Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Yes.

We're not breaking out the '13 guidance. We have a significant risk profile attached. In fact, we had 0 production contributing from the Utica in our forecast for '12. And we have a very minimal amount forecast right now because of its exploratory nature in the Purcell. So until we see the -- with the well results, drilling results, we're not forecasting that production. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Okay. And then you mentioned the drought conditions in Pennsylvania and some of the various conditions don't improve. Is any of that also baked into the '13 guidance? Or are you assuming the conditions do improve?

Well, the -- I can't predict the weather, but I can say currently, there is even-- since they had the restrictions, the restrictions have been lifted in our withdrawal sites. And we will start sometime today withdrawing water again up there as a normal course of business. So you're going to have these -- you're going to have the periods where you have some flood restrictions. It's dependent upon certainly rain, but we also are enhancing our storage capacity to allow us to frac through any extended drought periods. So to answer your question more succinctly, we have not forecast in our '13 guidance any risk profile attached to obtaining water for fracking. So we're comfortable with what we're building out in form of frac tanks, in the form of additional take points and in the form of accumulation areas to keep our frac crews busy. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Got it. And you mentioned the additional storage. Can you tell us what your current capacity is and how much you are adding?

Our current capacity will allow us to frac at least 2 stages per day and that is just as what we hold on the ground right now. That does not include where we are currently securing additional sites for take point, and it does not include any type of impoundments. So I would say we have plus or minus 500 frac stages -- frac tanks, excuse me, frac tanks available for fracking. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Got it. Plus or minus 500 available today and can you say how many you're adding?

Well, once we have -- it's not going to be where we're adding the frac tanks, it's going to be where we're adding additional capacity to existing sites and a couple of additional new sites for water withdrawal and the engineering of impoundment. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Got it. And then one more question related to that. I think you only had 2 or 3 locations that was impacted by the restrictions. How many withdrawal locations do you have in Susquehanna?

We have -- I'll let Steve Lindeman answer that.

Yes, there were 2 that were impacted. We have 5 total.

Our next question comes from Brian Singer of Goldman Sachs.

Can you talk to what you're seeing or expecting in terms of IP per stage from your Marcellus wells now versus what's historically been I think about 1 million cubic feet a day per stage I believe? And to what degree that your wells in the Marcellus that are currently online are being restrained if at all because of midstream constraint versus what you would want them to optimally produce?

Well, we have for example, the 2 wells that we've just announced on a per stage basis, these couple of new wells-- they're obviously very good wells, and they are above our average IP. We continue to see a fairly consistent level of production on a per stage basis. We are trying to extend our laterals and we're trying to add additional stages, but we do continuously or negated from as longer laterals as we'd like to drill out there on a consistent basis by virtue of the Pennsylvania not having any pooling provisions available to us. So in regard to our EURs and what we anticipate in the future, we'll look at that at year-end and make that kind of a determination once we get to the end to look at what the average stages of our 2012 program has been.

And are your existing wells that are producing in the Marcellus, are they producing at the levels that you would optimally want them to produce, or are they being restrained by midstream?

No. We have seen little restraints because some of the production we have or capacity -- production capacity we have in some areas is being affected by the unscheduled maintenance that we've seen and some downtime we've seen on various compressions. So that does affect our production profile. If you look at and you cobble together the unexpected downtime and some of the issues we've seen out there, which we are -- we along with Williams continue to work through, it has affected probably year-to-date, somewhere north of 5 Bcf of production.

Got it. And that's essentially incremental production from here that might not be included in the 368 stages that are behind pipe or completing?

Yes, we're risking some of that production that's behind pipe or waiting on pipeline when it comes on, and we also put an element of risk in on the wells we drill with the anticipated number of stages that we have forecast. And we do that in case we lose a plug in the hole. We have mechanical issues periodically out there that we can't get to the end of the, say, the toe of the well, back to the toe of the well. And instead of wasting the time right now, we'll bring on a well and then we'll clean out at a later day once production gets worked down.

That's great. And lastly, just going back to the water constraints topic. In some downside scenario where you would face greater constraints, do the planned infrastructure additions that you see coming give you the ability to bring on the 368 stages that have already been completed or are completing? And I guess on the earlier question, just to make sure we understood, what does pure water storage give you in terms of how many incremental wells or stages you could frac overall?

Well-- and I'll let Steve answer the latter part of that. But in regard to the 374 stages that we have waiting on completion, we feel very comfortable that we're going to be able to get all those stages fracked.

Right. And just in terms of our storage, what we're looking to do is to double our storage capacity at the withdrawal sites. So we'll have a significant amount of surplus of fluid available to us.

Our next question comes from Jack Aydin of KeyBanc.

What is your production today from Marcellus?

Let's see. I think it is -- it varies everyday, but it's plus or minus 650.

Okay. The second question, the lateral on those 2 wells, the 8 million IP and the 16 million, what was the lateral on those wells in each?

They were both 15-stage frac wells.

Okay. And how -- what was the cost running on those wells?

The cost was right at $6 million.

Okay. Now of the -- you had about 368 stages completed waiting and about 374 to be drilled, completed. How many of those do you think you might do this year?

We think we'll do all of the 300 and -- well, we'll turn in line all of the 368 stages and we will frac all of the 374 stages. All those are part of our expected stages that we'll turn in line and bar [ph] '12, we're estimating that we would be plus or minus 1,100 stages total.

Okay. Now with your takeaway capacity or takeaway of that coming about 1.5 Bs by year end, some operators are reducing activities in the Marcellus. Do you think you will have some access to additional takeaway capacity this year and next year because of other operator's decision to cut -- to reduce activities in the play?

Well, we're going to still see -- I'm going to turn that over to Jeff in a second. But we're going to still see, as we continue to build the infrastructure out, we're going to still see areas that we are infrastructure-constrained just by nature of where the drilling and completing is going to be. We'll be able to bring some on, but we might not be able to bring them on at full volumes. And I'll let Jeff make a comment also.

Jack, you're exactly right to a certain degree that the reduction in activity is going to open up some capacity on the pipelines. But I think the bigger factor that we're experiencing right now is, with Cabot taking more gas, additional gas down to Transco and companies like Talisman moving a lot of their production off the Tennessee line up to Empire [ph], and you've got some other producers Range, and there's probably 6 or 7 other producers that are moving gas in different directions because of recent pipeline completions and enter service this fall. That's what really relieving the pressure and the capacity constraints on Tennessee 300 line right now.

Dan, one more question, and you might not answer it. But when are you going to talk about the new venture, if you add it in a couple of plays, your 25,000 acres or so and you're spending money. When we might know which -- where you are being active?

Well, Jack, I'd be disappointed if you didn't ask a question that I couldn't answer. We have -- one of the areas I think we will have data on this year that we will probably discuss, and another area maybe both those areas we would discuss, but it's not a guarantee.

Is it gassy, oily play?

Yes.

That does it, okay. Now final questions. Do you do a mid-year reserve report or you don't?

No, we do not do a mid-year reserve report. Steve Lindeman is one who shepherds that, and he will start working on that til probably November, October time period to be prepared for year-end numbers.

Just based on the result of those wells, the EURs and everything, I mean it looks like 7.5, 11. Could you guess how high we could go in the EUR by year end?

Well, again, our data based on the Lower Marcellus is certainly adequate, and we're comfortable with the numbers that we have even all the way down to -- like Brian's question on the IP and booking per stage. But in regard to the Upper Marcellus, our data set is limited in the Upper Marcellus, and we'll continue to be cautious on our bookings in the Upper Marcellus until we see further data, but the data that we have seen, we're very comfortable with.

Next question comes from Michael Hall of Robert W. Baird. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Just wanted to, I guess, dive into the 2012 CapEx increment with a little more granularity. On that increase, can you kind of outline what the specific drivers of it were. It seems like some of it's clearly leasing, but just wondering if you could walk through some of the moving pieces there?

Well, on the 2 new wells that we're adding in the Purcell JV, we're adding also a rig in the Marmaton, and that is a rig that we placed into the -- in the Panhandle of Texas that we're currently drilling. We have the Utica well that we're drilling with Range and Range is also permitting a second well up there in the Utica, which we've included in our numbers. And we have a -- with the success up in the Marmaton, our operator where we're not operator, they continue to have a fairly robust program up there. Those are the primary areas that we're allocating the additional capital. And we're keeping the 1 rig in the Marcellus that either way that was not going to affect our production. It was just going to be reducing our cash if we went down to 3 rigs, but we're going to keep a rig running from August to the end of the year that we had originally had planned on setting on the sidelines til January. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Okay, great. That's helpful. And then I guess on the outlook for 2013, maybe could you just provide a little bit of a road map around the infrastructure and then given -- like you said, we continue to have, kind of, pockets of tightness. And how should we think about that for '13 relative to '12? Are the majority of those expected to be, let's say, debottlenecked by mid-year? Just some additional color there?

Okay, yes, now Jeff lives and and breathes this 24/7, so I'll let him answer that.

Michael, obviously, this is a process, and it doesn't stop at quarters and year ends. And we have permitted pipes out through '14 and '15 to try to design an infrastructure system out there that not only is safe and dependable, but also gives us flexibility and also increases our capacities to all the pipelines. So it is a work in progress. We do have some major compressor stations going to be completed early in the mid-year of '13. That's going to help us out quite a bit. Again, adding additional units to make sure that we have some backups, some spare capacity, that's obviously the goal. We also want to concentrate on lowering the fuel pressure throughout the system. And so as we grow the infrastructure, we will concentrate on trying to paint ideal conditions where wells have a better opportunity to produce at a 100% than they are at currently. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Okay. Will there be any sort of, let's say, lumpiness that you would highlight as we look at '13 on maybe a quarterly basis?

No, my expectation, Michael, as we've relayed to you that '13, we expect things to be -- to getting smoother in regard to what we can comfortably expect versus what we'll actually realize. The permits for our '13 program have been -- and all our location discussions with Williams has gone very well. Williams had submitted permits for the 2013 program, and we're 95% complete with that permit application for our '13 program. We'll have a little bit more spread and a little bit more capacity in not only existing areas, but we'll have some -- also some additional areas that we'll be able to move our gas through the existing pipe. So expectation is, it's not going to be lumpy. It would just be in the beginning of the year, we might hedge our bet a little bit like we have been this year. And the example would be -- a good example would be just the couple of wells that we brought on that were -- granted, very, very good wells. But if we would have brought the 2 wells at a -- each cumed over 1 Bcf, if we would have brought those on a month earlier as anticipated, along with some of the other wells that we brought on in July, it would've made a lot of difference in just what people look at as our second quarter numbers. So like Jeff said, it's not a quarter-to-quarter game with us right now. It's just a fluid, dynamic process that we are getting ahead of, and we're at the tail end of coordinating the passing the baton from Cabot to Williams on getting all these gathering lines in sync with where we have drilling rigs. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Okay, great. That all makes sense. Appreciate the color. Just a couple more as you look to the end of '12, would you care to put any sort of exit rate assumption out there and then kind of what you feel like the backlog in terms of uncompleted and are waiting on something, let's say, looks like as you head into '13 in the Marcellus?

We're still going to stick with our -- just our pretty wide range guidance right now on the exit rates. Certainly, as you can see with the number of stages that we had already completed, waiting to be turned in line and the activity that we have ongoing, it's fairly safe to say that we're going to have a robust exit volume, but we're not prepared to lay it out there. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Okay. And then in terms of backlog, I mean, relative to the current backlog, waiting on pipeline and/or completion, do you think it will be pretty similar as you head into '13 or do you expect to work that down materially?

Well, I would expect with us keeping that. As we mentioned before, we were going to get down to 3 rigs and going into January, we were still going to have a backlog of stages that rolled into '13. Now keeping that rig, our backlog is going to increase, and I would think that backlog will probably be between 350 and 400 stages. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Okay. And then I guess just 2 more housekeeping ones on my end. Well costs, let's say, per area in the 2013 outlook, would you care to provide those? Give us the rig counts. Just curious what you're seeing on a well cost per area?

Well, we're in the $6 million plus or minus range in the Marcellus. We're in the -- as we've mentioned, the $2.4 million -- or $2.9 million to $3.4 million in the Marmaton. We're in the $6.5 million to $7.2 million in the Eagle Ford. The Purcell wells are going to be right now because we're going to have some evaluation process going on. We're going to be $9.5 million to $10 million -- $10.2 million somewhere in that regard. The Utica well -- somebody help me with the -- the Utica well is going to be $7.5 million to $8 million, something of that nature. And that has science attached to it also with us coring and things like that. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Okay. And then on the 2 wells that have cumed over 1 Bcf each, what would be the cume during the roughly 39-day or whatever, call it a 30-day period on your 11 Bcf type well?

Less than that. I don't have that number. Yes, I'm sorry, Michael. I don't have that number handy with me right now.

Our next question comes from Matt Portillo of Tudor, Pickering, Holt. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just a quick question to clarify on the CapEx side. I'm just working through the implied run rate into the back half of the year. And to get to the midpoint of the guidance range I'm seeing something around $250 million to $275 million per quarter. If I was to annualize that number into 2013 and then looking at the rig count allocation that you guys have, it would put me at something probably above the $1 billion in CapEx guidance. Can you just provide, I guess, any color around that and maybe what you may be spending incremental capital in the next 2 quarters that may not be there in 2013?

Matt, this is Scott Schroeder. One of the things that Dan highlighted as part of the capital increase is a doubling of the lease ac. And the lease ac run rate for '12 is higher than the run rate has been. So that would contribute part of it. Again, what it's all going to boil down to for '13 is what we think the underlying commodity prices are for both commodities. We've given you a kind of a wide production range, but if you kind of look at the midpoint of that, what's your cash flow? We're going to target the cash flow. And if it ends up -- cash flow ends up being a little above $1 billion, we'll probably be a little above $1 billion, if it's below, we'll be below. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Great. And just on that leasing side, is there a rough number you guys can provide us on the leasing for the full year?

For '13, I would say it's probably back to the $50 million or less range for next year. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, great. And then just, I wanted to clarify on the July production number, I think you said roughly 650 million a day, is that a gross number?

That's a gross Marcellus number. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And how does that compare to June?

That's probably about 30 million a day to 35 million, to 40 million a day higher than the June average. Actually than the second quarter average. Second quarter average is right around 615 gross for Marcellus. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, great. And then just the final question for me. I just wanted to clarify on the production guidance for 2012. You are baking in some risked volumes given the issues around the drought or you're not baking in anything at this point?

No, we're -- the risked volumes that we bake in -- one, we have not included anything in the Utica. Two, we have very, very little production attached to our Purcell right now, and we feel fully comfortable that with the -- our plan in place and the securing of additional sites, we feel fully comfortable about getting our production volumes with the -- not only what we've already done, the wells we've already completed waiting on infrastructure, but also the amount of capacity we have to frac between now and the end of the year. Even if you had some drought conditions, we feel fully comfortable about being able -- matching our guidance. And we have not put -- added any risk profile to that because of those comments.

Our next question comes from Charles Meade of Johnson Rice. Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: Let's see, a couple of quick questions. First, on the Marmaton. Those look like-- at least the one well you guys talking about is really encouraging, and I'm curious what -- do you guys have a view on what drives the divergence between your wells that are really good and wells that are not as good? And do you think -- what are you doing to advance the ability to figure that out pre-drill?

Well, the biggest factor geologically is the extent of fracturing in and around the well bore. And that is contributing to the differential and the delta. We are doing some things out there, for example, we're going to be drilling our first operated stand up 640, which will have longer laterals and more stages and certainly, we think, the possibility of intersecting additional fractures, but that's the overriding royalty why you have more delta in this particular area that you might in the other areas. And I'll let Matt make a brief comment attached to what he's seeing out there also.

I think also with our longing programs that we have now, we are better able to identify our fracture systems and also a real key to our completions now are pack replacements. We identify fracture forms and are able to place our packers in more ideal position and better place our fracs. Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: So you're just -- you're interpreting the open hole log on the whole horizontal section and deciding-- kind of just deciding where you're frac is going to be more closely spaced or something.

Yes, that's part of it and also we've done some things to better isolate the individual stages between -- during the frac. And also, I think we've been able to identify some better areas where these individual fractures have formed and areas are. Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: Got it. And then one follow-up question, Dan, thanks for addressing that pricing issue in the Marcellus head on. But as far as what we should look to, am I right in thinking that it's really the Dominion Basis Swap that we should be paying attention to for your -- for the pricing that you're going to realize up there?

I'll let Jeff, fill that.

No, not necessarily. Demand is kind of a weird situation. The Dominion index and Columbia Gas Transmission index, both very traditional Appalachian-type indexes. When we first got started up there, pretty much a lot of people traded off that Columbian index, that's no longer very applicable and so a lot of people turn to Dominion. But mostly people have turned to just plain old NYMEX-type pricing. And so on the fiscal side, we have, too. And so -- but when you take our existing term business and you look at the 3 different pipes that we're on, all 3 pipes trade different indexes. So what we've tried to do is just put them all in a bucket and kind of throw it out on a weighted-average basis. We're pretty darn close to last day NYMEX.

Our next question comes from Joseph Stewart of Citi.

A follow-up question on the Marmaton there. So you're mentioning that the results are largely driven by the naturally occurring fractures. How many drilling locations have you currently identified there?

I'm going to let Matt fill that, and again, that was part of the reason why we added the extra rig in there is to identify a larger swath of our acreage and so the assumptions that you roll into that, if you had all of it available-- Matt, I'll let you fill in.

If you look at these individual fracture forms and look at our positions on mid-quarter, as Dan said, we're down in Texas now and starting to look at a new area and also looking at some other areas as well. But I would say the locations are going to vary from between 400 and 500 gross locations.

Okay. So are those locations which appear to have the naturally occurring fractures?

Well, as we say, we're investigating and looking at new areas down in Texas and some other areas in Oklahoma. But in the areas that we're in now, yes, they would have the natural occurring fractures, that's correct.

And Joe, just to comment on that, we have a lot of -- again because of our leasing, we have a lot of vertical wells and areas that have shown fractures in the past, but we have not done extensive -- nobody's done extensive horizontal drilling in some these new areas to determine the full extent of the fracturing. So that would be the risk profile you would assess against it.

Got it. Okay. And then I apologize if I missed this, but given the 1.5 Bs per day that you're expecting to have by year end and then also just kind of looking at your Q2 volumes, if you held Q2 flat, you'd basically be at the low end of your guidance for the year. So should we maybe expect kind of an updated range or maybe even an increased range on the guidance by Q3? Or would you prefer to just kind of wait and maybe just hit the high end or beat it?

Well, we've had discussion about our guidance and the width of the guidance that we have, 35% to 50% and we realize a fairly large truck can drive through that. But we felt that right now, staying consistent, not have a whole lot of moving parts in our guidance and just to continue to work through the delays that we've seen in the gathering lines. We thought that's prudent, and if we are successful in topping out our guidance, then that's great. But we certainly feel very comfortable that we're going to be within guidance.

And our next question comes from Bob Brackett of Bernstein. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: Can you talk about what you learned from the Brown Dense well, and what it cost you to learn that?

The cost was the acreage cost of the 13,000-plus acres and the cost of the drilling, which we wrote-off as our dry hole cost, which was around $10 million. And right now, we're still, again, have learned that it's productive, continued capital being spent in the area by different operators and making an effort to determine how to make it economic up there and compete with the other plays that companies have to allocate capital on. So we're not -- again, because we write-off the well, we're not saying we're condemning the play. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: And do you think the poor results, I guess, implied in the write-off-- are they the result of a completion, or do you think it's the geology or some combination?

Well, I think it's just the early stage of going into a virgin area to drill well when you have decisions on where you're going to place the well in the zone and what type of fracs you're going to place on it, how you're going to space those fracs and the well we drill, exploratory, again, in nature. We only had 10 stages applied to that. And it's gathering information that's going on not only in the Brown Dense, continuing gathering information in the Tuscaloosa Marine Shale. We did the same thing as we gathered information in every other play, the Eagle Ford, we're doing that now, in the Purcell. We did that in the Marcellus, and it's just a very early entry. Some play, some areas, the key to success is very obvious and upfront. In other plays, the key to success takes a whole lot more study and evaluation and technology to get there.

Our next question comes from Robert Christensen of Buckingham Research Group.

On the ops report, my one question relates to the Eagle Ford. You say it's very early results in your down spacing program. When will we be more down spacing and when will we start to establish that the down spacing is working or not working on a very broad area of your acreage? When will we know some of that?

Yes, that's a good question, Robert. And with -- obviously, we all need to be cautious without a big sample pool. But with that said, we are -- we have drilled 2 additional wells that are spaced 400 feet apart. And we have-- Matt's group has scheduled the frac to occur in the middle of August. So we will -- will do that and get another data point, but from the information we've seen on the 2 wells as we mentioned, the 30-day average is greater. In fact, one of the wells had been on about 110 days and one of the wells is still producing at 400 or so barrels a day. So that is pretty good data that says that-- a couple of things. One, that the spacing was not a big issue; and two, that the zipper frac we think, which was -- these were the first 2 wells we did the zipper frac, we think it probably had a positive effect overall on the proximity of each frac that we did and the results that we're seeing.

But my point is, I guess how many more down spacing tests will you run this year and next year? When will we start to be able to put a big circle around this and say it's broad, broad in nature, the success of down spacing as opposed to in a select area.

Well, we can extrapolate a little bit now by the other wells we've drilled and the geology we've seen and consistency in the geology that we've seen in the other areas we've drilled. So we can extrapolate a little bit, but to specifically have a full-blown development program out there right now, we're not implementing a full-blown development program out there right now until we continue to see how the wells performed, all the wells perform, long-term. But again, in '13, I would expect towards the end of '13 that we would have a couple of more pad sites that would give as additional data points in additional areas that would continue to enhance our evaluation.

So perhaps by '14, we could rule it in on a broad-based basis or not? I mean, we just need more time, I understand.

No, I think that's very realistic.

The next question is a follow up from Biju Perincheril of Jefferies. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Going back to the discussion on price realization. Gas that you're flowing on the Tennessee line. Is that subject to the TGP zone 4 pricing? Or are you getting some other index on that?

The answer is no. It's not -- we do not sell off that index. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Okay. And if you -- if you wanted to flow additional gas on Tennessee today, would that then be subject to zone 4 pricing or...

No, no, it would not. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Okay. And then the Springville expansion, is that still on target for August completion?

Springville has a couple of phases to it. There are some units being commissioned as we speak. And so we don't have an exact date, but certainly, in the next short term. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: And for that next phase coming on, how much capacity would that add?

The next compressor will add approximately 100,000 a day of capacity and then the second phase of that will add approximately 200,000 a day of capacity. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Okay. And do you have timing for that 200 million (sic) [200,000] a day?

We expect that kind of early fourth quarter. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Got it. And then lastly, the 2 wells that you highlighted that produced over 1 Bcf a day, what was the lateral length and stages on that, and also the cost?

Let me grab that. The costs were, I think-- let me see what's the -- Steve, what do you have there...

17 stages.

Both of them?

Yes.

Both of them are 17 stages. So the cost is probably about $6.5 million, something like that. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Great. And those were in the central area?

Yes.

Our next question is a follow up from Michael Hall of Robert W. Baird. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Just one quick one on the -- more of the macro environment. Just curious if you had any sense of industry backlog as it relates to kind of wells waiting on completion and/or pipeline in Northeastern PA?

No, Michael, I don't have a -- exact numbers or any better intelligence than some of what we all read out there. I know there's some wells that are drilled waiting on capacity buildout and that capacity buildout is down the road, but I do not have the exact count on those -- the number of wells.

Our next question is from John [indiscernible] Capital Partners.

The early results in the Upper Marcellus look good but the lower is, obviously, still better. Kind of, how do you see that playing out once -- are you going to do enough that you've increased your knowledge and the certainty of that and then continue to drill the lower? How does that look going into 2013?

Well, the drilling we're doing right now is predominantly in the lower. We plan on continuing drilling predominantly in the lower as we continue to gather data points, which we will drill some additional data points between now and through our '13 program in the Upper Marcellus. The plan would be to gather information, have the confidence, and then once we get to a more intense pad drilling, that we would augment some of that drilling with the reduced spacing that we've implemented in this particular area, similar to that pattern.

Got it. So I guess the lower recoveries you would more than make up in the synergies of drilling from the pads?

Absolutely. We expect to have increased synergies in our pad drilling process. We just did not -- we're just not doing that right now.

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

Okay. I appreciate it, Emily, and thanks for the attention for this quarter. As you can see, the program that we've laid out, we'll continue to follow it within what we think is a fairly robust production guidance process. There was comments in regard to our reserve bookings and at the end of the year, once we do that, we think we are also going to have a very robust reserve recognition at the end of the year. That's going to translate into, I think, a top-tier finding cost and certainly a very nice portfolio on the books by the end of the year. Stay tuned. We have more to come, and I look forward to visiting with you all through the third quarter. Thank you.

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