Coterra Energy Inc. (CTRA) Q1 2012 Earnings Report, Transcript and Summary

Good day, and welcome to the Cabot Oil & Gas Corporation's First Quarter 2012 Earnings Conference Call. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Dan Dinges, Chairman, President and CEO of Cabot Gas.

Thank you, Shea. I appreciate it. And good morning, and thank you for joining us for this call. A couple of members with me on the management team, Scott Schroeder, CFO; Jeff Hutton, our VP of Marketing; Steve Lindeman, VP of Engineering and Technology; Matt Reid, our VP of Regional -- and Regional Manager; and Todd Liebl, our VP of Land and Business Development. As you're aware, the standard forward-looking statements included in the press release do apply to my comments today. At this time, we have several things to cover and expand on the press releases that were issued last night. I'll cover the first quarter financial results, recent successes from our drill bit effort, followed by a discussion of our operations. Now before I do go into the details of these topics, I'll start with a brief highlight of last night's release. Cabot grew production 58% over the comparable quarter last year, including a 55% growth in natural gas plus an impressive 138% growth in liquids. The growth figures include only a few days of the new production we recently brought online in the Marcellus coming from a 7-mile step-out to the east of our existing production. The wells have free flowed 70 million to 80 million-plus cubic foot per day since being turned in line. Also of note are increasing liquids production. It's continuing in both Oklahoma and Texas. Plus, we'll cover briefly the initial down-spacing success we had in our Buckhorn area of the Eagle Ford. And finally, we're excited to announce our exposure to the Utica liquids window of about 50,000 net acres. This potential will be tested with a well to spud this summer. Let's move to financial results, and last night the company reported clean earnings of approximately $29 million driven by our significant production increase that did more than offset the weak natural gas prices. On the production side, in terms of the significant uptick in production, the Marcellus, Eagle Ford, and to a little bit lesser extent, the Marmaton were the driving forces. One item to note is that the 2011 first quarter results include 2.5 Bcf of Rocky Mountain production, which we sold last year. The equivalent pro forma growth would be about 70% regardless that the quarter was a record breaker production-wise. The first quarter production landed at the midpoint of guidance even with the shutdown of the Lathrop Compressor Station during the last days of the quarter. This event will not change our full year production guidance of 35% to 50% growth, which we reaffirmed last night. Our net exit rate for natural gas for the quarter was approximately 623 million cubic foot per day, while oil was 5,870 barrels per day. With the completion successes in April, some of which are provided in the operations release, April's net production has averaged 655 million cubic foot per day for gas and 6,500 barrels of oil per day, which provide the basis for modeling the second quarter. For cost guidance, we updated other taxes to fully reflect the new impact fee in Pennsylvania. Additionally, we updated exploration expense and discussed pension expense. Let's talk about our plans a little bit. The Cabot operation plan remains basically unchanged for 2012. We continue to focus our capital allocation towards our drilling in the Marcellus, and the remainder of our capital dollars are being allocated in the oil window of the Eagle Ford and into the Marmaton. Currently, we have 7 rigs operating in our plays between Pennsylvania, Texas and Oklahoma. We remain committed to balancing these efforts with our anticipated cash flow. However, as you might be aware of the forward curve lower than our February forecast, our plan does result in slightly more utilization of the revolver this year. We have been asked the question a number of times, will we slow down or change our investment program? Really, my answer is this, that with the strength of the balance sheet and our objective to secure all our acreage in the best -- maybe the only return gas play in the country, and with the continued growth of our liquids production in Texas and Oklahoma, we plan to keep our operation program as budgeted. And regarding hedging, the company did not add any hedges since our February call. Our existing hedges are on the website and represent 39% of midpoint guidance. We also have 7 contracts in 2013, 5 gas and 2 oil. We continue to look at potential for hedging a portion of our oil production as we increase that production strength, but we do not anticipate hedging gas at these levels. Now let's move specifically into the operation area in the Marcellus. Our results in Susquehanna County continue to excel. Since our last call, we have achieved a new production record of 678 million cubic foot growth per day, which is over 70 million cubic foot per day greater than our last call. A review of our production history indicates we have produced over 250 Bcf from our Susquehanna area since first production 39 months ago. This translates into close to or over $1 billion in revenue and approximately $125 million paid in royalty. This is substantial evidence of the positive impact we're having on the local community up there and certainly the state of Pennsylvania. Cabot continues to operate 5 rigs in Susquehanna with our plan to reduce this count during the second half of the year by a couple of rigs. In operations release last night, we highlighted a couple of key data points. Specifically of note was one 2-well pad site with a total of 40 stages completed, which yielded a combined 30-day average of 40 million cubic foot per day, a couple of pretty good wells. These 2 wells were slightly longer laterals than our average well and illustrated the efficiencies gained with longer laterals. A second key data point, and I think most importantly, is our 5-well pad site on the east portion of our acreage. This is approximately 7 miles from current production. These 5 wells we completed a total of 92 stages, as highlighted last night. And it is worth repeating, these 5 wells have averaged about 78 million cubic foot per day over the last 20 days. The successful completion of these wells indicates our eastern acreage should be equally as productive as the central portion of our area, and certainly without question, de-risk another substantial portion of our acreage. Another initiative underway in the Marcellus is our pilot program to determine the optimal well spacing and also to look at the Upper Marcellus. We recently completed 2 lateral wells spaced 500 feet and located between 2 existing wells that had a combined cumulative production of over 10 Bcf from the Lower Marcellus. One of the 500-foot space laterals was landed in the upper Marcellus, and the other was landed in the lower Marcellus. Both of these wells have been completed and are cleaning up very nicely. As these results come more available, we will share those results with you when we have those. Currently, we have 238 stages completing, cleaning up or waiting to turn in line and an additional 333 stages waiting to be completed in the Marcellus. Our new completion crew continues to make progress with its efficiency. For March, this crew completed 107 stages, a new high for Cabot. Because of the efficiencies gained and the macro outlook for natural gas, we are no longer planning to bring a second crew in for 2012. In regard to our infrastructure up there, our plans continue on course at a consistent and steady pace. During the first quarter, we reached a significant milestone with the start-up of the Zick [ph] compressor station. Although we are free-flowing and currently only utilizing the dehydration and measurement facilities, the station is operational. The compressors will be commissioned during June. Other stations, new pipelines, additional connections and upgrades to its existing facilities are continuing as planned. And we have indicated before, we intend to exit 2012 with approximately 1.5 Bcf takeaway capacity. Also of note, I might mention that the Lathrop station is back at 100% with all 7 compressor units operating. In regard to the pricing up there in the Marcellus, let me give you a quick update. Everyone is aware of the weak commodity prices the industry is experiencing. In addition, we, as well as other Marcellus producers, have experienced some discounting to the historic Appalachia Surplus and Pricing Index. However, with the flexibility of our Springville line to Transco and the Laser system to Millennium, our pricing is flat to minus $0.03 to $0.05 below the Henry Hub. We expect that trend to continue in that range. Now let's move to South Texas, into the oil window of the Eagle Ford and our Buckhorn area. The company has drilled a total of 30 wells. Each well is 100% working interest well located in Frio, La Salle and/or Atascosa County. 29 of these wells are oil production with one well waiting on completion and one well drilling. As we highlighted last night, our down-spacing test results in the Eagle Ford has indicated success based on the early test data coming from the 2 wells. These 2 wells were drilled with approximately 5,900-foot laterals at a spacing of 400 feet between the wells, which translates into approximately 55 acres per well. The test rates of each well had approximately 790 barrels of oil per day over 24-hour period are certainly encouraging. We plan to continue to monitor these wells with plans for additional down-spacing test later this year. Should be these results be implemented in our total development plan, we would have anywhere between 550 to 700 total potential locations just in Buckhorn. Gross production from both Buckhorn and our Presidio [ph] area, which is a joint venture area with EOG, is approximately 9,800 barrels per day, with our net production from the Eagle Ford at 5,700 barrels per day. Cabot intends to drill or participate in 20 to 25 net Eagle Ford wells in 2012. Now a brief statement in our Marmaton effort, which has a couple of pretty nice wells up there. Cabot has 6 operated wells on production with 2 wells completing and one well drilling. The latest 2 operated wells have provided very positive data points to continue to assess this play. The results were in last night's release. The most prolific well has a cumulative production of 50,000 barrels of oil equivalent in the first 50 days of production. That's about 87% oil. We will continue to drill with one operated rig in the area at this time and probably for the remainder of '12. In the Marmaton, our effort continues to identify the more highly fractured areas of the play with slightly over 69,000 net acres. That's our perspective for the Marmaton. We certainly have a lot of running room up there. Shea, with that, I'll be more than happy to take any questions.

[Operator Instructions] Our first question comes from Brian Singer of Goldman Sachs.

I wanted to see if I could follow up on the comment in your -- that you said in your prepared remarks, that you were going delay bringing in a second frac crew. Does that have an impact on maybe pushing CapEx into more towards the bottom of your range for this year? Or do you still plan to complete -- and will you build a backlog as a result? Or do some of the efficiency gains you highlighted offset that?

Well, we'll continue to have a backlog simply by the nature of drilling from pads and how the gathering lines are being hooked up to completed pads. We have a significant effort to get those gathering lines to those pads that have been completed, but that will continue to have a backlog. In regard to -- certainly, we're gaining the efficiencies from just the 24-hour crew implementation out there. We do not expect there to be a great deal of reduction in the CapEx because we're going to continue to -- because of the average stages per month, we're going to continue to complete as many stages as we had originally planned, even bringing another crew in for a period of 2012.

Okay. And then do you anticipate drilling any additional step-out wells to kind of further gain confidence in area like this [ph]? Or do you feel like you have largely done that with the step-out wells that you announced to the east here?

We've had a lot of confidence probably certainly more than maybe some of the comments that we've heard. We've had a great deal of confidence in our acreage position. We are drilling wells in all areas of our acreage position. It's just the ability to get those wells hooked up. And flowing would be delayed somewhat just because of the distance from the compressor stations that we're putting in and the interstate pipeline. But we would gain the data from those particular wells by simply the drilling, which we have.

Our next question comes from Amir Arif from Stifel. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Just 3 quick questions. Just first, on the Upper Marcellus zone test, the well that's cleaning up, do you have a sense of timing of when you'll have some numbers and confidence or color to provide on that?

Yes. We've been flowing back. The wells, I would say, have cleaned up very nicely. We have -- and we'll provide color both on the micro-size work that we did and the offset wells and the monitoring there. That was positive to our thesis that the upper Marcellus is not being drained, the Lower Marcellus completions. We are flowing back those wells as we speak. And we anticipate us giving more color on that, I would say, within 45 to 60 days. But so far, so good. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. And the compressor does seem to be not affected by the Lower Marcellus from what you're seeing on the...

Yes. We're pleased with the pressures we saw. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: And then secondly, on the Eagle Ford, the 400-foot spacing, I mean, it's obviously going to increase the number of locations you have, as you mentioned. But I noticed the IP rates were also better. But was it just the frac? Or are you -- is it just longer laterals on the wells you did?

Well, we're -- that's one of the data points that we're looking at on whether or not the proximity of the zipper frac we did enhanced the production from these wells or if we happen to be just landed in a better geologic position. That's something that we are going to monitor in these wells. And certainly, we're anxious to drill our next down-spaced wells to see if we have consistency in those results. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. And then just on the Marcellus production rate, I know you have 1.2 Bcf takeaway capacity at the end of the year. What kind of production are you estimating as the exit rate for the year for the Marcellus?

On the infrastructure at the end of the year, we anticipate the takeaway capacity to be at the 1.5 Bcf per day level instead of the 1.2 Bcf. And as far as the -- well, we haven't yet on the exit rate, and at this stage, not prepared to. But our guidance is going to -- we're very, very comfortable with our guidance that we've given in between, the total year, the 35% to 50% production growth. We just haven't given the -- pinpointed the exit rate at this stage. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: And then just one final question. One of your peers has talked about cost pressures coming down, capital efficiency improving. Do you see the similar impact just from service cost coming down as cash to exit is less or slow down?

Yes, we have. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Can you quantify that?

Well, we are saying in our -- we have actually kind of expressed it earlier when we executed -- up in the Marcellus, when we executed our pumping service contract. We recognize at that point in time that the cost were certainly coming down. And in the Eagle Ford, we recognized the same thing, that the pumping services and some of the other services were coming down. Pumping services, percentage-wise, I think, a little bit greater than maybe the 5% to 15% in various other services.

The next question is from Eli Kantor of Jefferies & Company. Eli Kantor - Jefferies & Company, Inc., Research Division: On the last call, you had mentioned that if gas prices remain at these levels, that you'd introduce the Marcellus rig count to 3 from 5. And from your comments this morning, it sounds like you plan on maintaining the 5-rig program. So I was just wondering why the reversal on thought process there.

No. I'm sorry, I didn't make myself clear. What I had mentioned is we are going to continue our capital program as we budgeted, and we have budgeted a reduction of the Marcellus rigs towards the middle part to latter part of the year by releasing a couple of rigs. And we are still on that program. Eli Kantor - Jefferies & Company, Inc., Research Division: So the current CapEx program assumes that you get down to 3 rigs by the end of the year?

That's correct. Eli Kantor - Jefferies & Company, Inc., Research Division: Okay. And then in terms of Marcellus EURs, it looks like results, at least the ones that are published, are trending north of the 11 Bcf type curve. Can you just talk about how you think about EURs internally and whether or not we should expect a revision and what the size and timing of such a revision might be?

Well, we have seen, certainly, some very, very good wells out there. And the EURs, certainly, are north, in some cases, the 11 Bcf. It's dependent on the lateral length. And when you -- we're drilling our wells up there, and without cooperative or forced cooling, we're bound and restricted at times to the total lateral length of the wells that we can achieve. And with the lateral length being either extended or reduced, it takes spacing between 200, and say, 225-foot between each stage, how many effective stages we can pump. So our 11 Bcf well is indicative of what we look at as a 15- to 16-stage type well. In the cases where we are able to get extended laterals and more stages, I think we're seeing greater EURs. And certainly in the less stage areas where we're restricted because of the holdout on a mineral owner, then there is slightly less. And then you will always have areas that if you find just one of those good areas, that you can really get some significant wells. Eli Kantor - Jefferies & Company, Inc., Research Division: Okay. And on the Brown Dense, can you talk about your activity there for the initial completion? Where within the horizon you could place a lateral? What are your drilling plans for the balance of the year? And are you guys still within the plan?

Right now, as far as our drilling activity, we completed the well. And kind of footnote out there, this was our initial well in the area. It's certainly not many data points to go by and our initial well design as we go into each area without a lot of data. We purposely try to manage our exploratory dollars, and we did that in this particular well where we only drilled down about a 3,000-foot lateral. We anticipated only about 10 stages, which we -- that's what we completed at over a couple of hundred barrels per day completion on the very first test. That's not too bad, particularly if you extrapolate out with the added efficiencies in the future and more frac stages. We landed our well kind of in the middle of this section of the Brown Dense, and we didn't have any significant drilling problems. Right now, with the strip price of natural gas, we do not anticipate going out there and drilling additional wells. We'll continue to gather the data points with the other activity that's being conducted out there. And we're looking at and talking to folks about the acres out there, but we're not actively out there with a bunch of brokers leasing.

The next question comes from Pearce Hammond on Simmons & Company. Pearce W. Hammond - Simmons & Company International, Research Division: Dan, when will that Marmaton rig move down to the Eagle Ford? Is that still on track later this year?

Well, we have planned a lot of that -- not a lot of that, we plan on moving that rig down because there is -- some of our acreage is subject to the hunting season restrictions. And with the last well we drilled and some of the sites that we're doing up there, we elected to continue to drill a couple of more wells, which we've done a couple of the wells that we announced. They've been pretty good wells. We're still looking at the science that we're applying up there. And at this stage, we have -- we've decided that it would be beneficial to our program to continue to plan ahead, to continue to gather the data with the drilling information we're gathering and keep the rig up there at this time. Certainly good efficiencies, good returns with a 2 to 3 [ph] type million dollars wells, and seeing some pretty good results. So that's what we're going to continue right now. We have not made a final decision whether or not we're going to continue drilling up there all year or drill -- move the rig down into the Eagle Ford. Pearce W. Hammond - Simmons & Company International, Research Division: Great. And then moving to the Utica acreage, just a general overview. How do you feel about acreage like as far as the infrastructure is concerned? You're going to start your first well, you said, this summer, kind of plans beyond that for the rest of the year.

We haven't made any forward-looking plan up there for the remainder of the year. We are certainly excited of the data points that we have up there about where our position lies in regard to the volatile oil window. And we think we are in a good section. And the thickness, we think, is going to be fairly robust also. So we're looking forward to the test range. We'll operate the well with 50% and capital of 50% this summer. I'm sure we'll take the data. We'll communicate the exchanged thoughts on what we do moving forward and make that decision, but we haven't rolled out anything further on a development plan at this stage. The infrastructure is still going to need to come in and improve in the area. I'll let Jeff make a brief comment on that.

Okay. Where this acreage lies is quite a bit of conventional gas, oil activity, and so there is numerous pipeline. However, they are probably not modestly sized. But there are some -- there is some activity of up there that -- where our infrastructure has already began. So we hope to kind of piggyback on that. And as we get closer, we'll probably give you more details. Pearce W. Hammond - Simmons & Company International, Research Division: Great. And then finally, Dan, just general thoughts overall in the Marcellus. Are you seeing a large drilled and uncompleted wells just kind of across the industry? And if so, is that due to limits on takeaway capacity or service constraints or just low prices?

I think there is certainly wells that are drilled and completed shut in and infrastructure buildout with the programs that are on the board is ongoing up there, and I'm sure that has a bearing on it. But it's also worthy of note that there has been a substantial number of rigs drilled [ph] in the Marcellus are being laid down. So as far as ongoing buildup of wells out there, I don't have the authority to get the count from all the operators, but I don't look at that as being a significant build of Marcellus. Well, I think there are quite a few peers, but I don't think there's just ongoing build of wells out there.

Your next question comes from Michael Hall of Robert W. Baird. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: I guess just a couple of quick ones for me. In the Marmaton, apologies if you already laid it out, but what -- any sort of revised outlook on the location and inventory there on the acreage block at this point?

Well, at this stage, we have 69,000 net acres up there. What we're trying to do is identify the fracture stages out there. And I think one of our last fragmentation tests is 61,000 net acres. We've ramped that up. But I don't know, we think we have anywhere from 200 to 300, 400 depending on the spacing. It's a large range right now because we continue to gather data. Sorry, Mike, I can't be any more specific in that at this time. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: It's okay. So I guess you need to some natural fracturing, so it's a function of kind of just getting the acreage. Do you have -- remind me, do you have seismic shot on it? Or is that how you're identifying the fractures or...

No. Well, we have -- we don't have 3D shot. We have -- we've gathered that 2D lines up there that are available, and we've got some reprocessing and things on the 2D lines. And there is certainly a lot of vertical well data points that we're trying to integrate into our reprocess side. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Okay. That's helpful. And then the other one for me, just more big picture. Dan, you made a comment in the release that given the environment, looking to be opportunistic, should we read into that at all? I mean, have you changed in terms of your general approach to looking at the market, obviously wanting to maintain the optionality around the Marcellus, the core Marcellus asset? But are you looking to get more aggressive in some of these more emerging plays, with either leasing other sorts of acquisitions? Should I read into that comment at all? Or am I getting ahead of myself?

Well, I think every company on the market is trying to find the next deal that will slot in above the returns that you're allocating -- the areas that you're allocating capital to and comparing the type of returns you get. And in our areas that we -- that all is aware of, we continue to try to capture the acreage in the Marcellus. And we have multi-year drilling programs and locations out in front of us in each of the areas that we're currently active and allocating capital: Marcellus, the Eagle Ford and the Marmaton. We also -- now with 50,000 net acres in the Utica area, that's going to be a substantial -- with success, is going to be a substantial area of future activity for us that we think would slot in, assuming we're in the liquids window there of a good return-type potential. And we're also drilling a well in an area we had talked about. So we continue to try to find those opportunities to add capital efficiency to our program. Unfortunately, even though the Marcellus is a wonderful gas play and probably one of the best gas plays in the U.S., with the gas strip where it is, it's just -- it's difficult. We still make a return up there. It's not yielding the return we would expect forever. We think we will show significant enhancements to the returns in the future. We think those returns will be helped by commodity price down the road, and everybody is trying to guess when that happens. We think we'll also see significant uptick in margin improvement at any commodity price once we get to pure pad development drilling from our operation up there. But as far as the read-through in what we're trying to do, we continue to try to enhance our capital efficiency. And frankly, if we had all our acreage secured in the Marcellus right now and held, I think we would allocate a significantly a greater portion to the liquids opportunities we have. And again, we have many, many, many years of liquids drilling in front of us, and we continue to grow in liquids we've been able to demonstrate with 138% growth just most recently. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: That's helpful and certainly very noteworthy in the increased inventory in the oil projects. I mean, along those lines, as you think about the second half, is there any thinking of potential around maybe bumping the capital spend in these areas as you start to have more and more in the way of kind of liquids- and oil-rich inventory to set up for a stronger liquids ramp in 2013? Or is it still too early to be thinking about it?

Well, no. It's necessarily not too early to think about that. We are already starting to kind of look at the horizon in anticipation of presenting our '13 budget to our board in October. And I would venture to say that we will have a larger component of liquids drilling in the '13 budget. But again, I'm not going to deemphasize the window we're in right now, and it is a finite window we're in. We continue to allocate capital to capture our Marcellus acreage, and that does have a squeeze on us a little bit right now. But at the end of the day, and looking at the amount of reserves that we are able to stack on our books through our Marcellus drilling and the growth, both in production and in just pure reserves on the books, in a couple of years, I think shareholders are going to recognize that the drilling that we implemented today is going to have a significant advantage if we have a little bit more balance between supply-demand phenomenon and the gas price.

The next question comes from Joe Allman of JPMorgan. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Dan, how much of the Susquehanna County do you think you've de-risked at this point?

Well, I think we have de-risked probably 70-plus percent. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. And have you written any part of Susquehanna County off based on any new information?

None. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. And then in terms of the longer lateral wells, maybe you said this earlier, and I'm sorry if I didn't catch it, but what's the cost of those longer lateral wells?

We're in the upper $6 million range to low $7 million if we get to 20 stages. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. That's helpful. And then in the Marmaton, that one well that you -- was within your lease, I know you previously disclosed that in your presentation, what made that well so much better than the other wells?

Well, when you're going to -- when you find the natural fractured areas, and again that's part of our effort up there, I think we can see these type of wells. And that is our play concept, really, when we went up there in the first place. Our challenge we knew was going to be trying to identify the areas that had the significant fractures. And as we continue to drill and gather data and try to do as much science as we can in that regard, where we find good fractures and we find good efficient completions, we think we can repeat these type of wells. That is the poster child right now of the wells we drilled up there, but certainly, we have an expectation that it's not going to be the last. Joseph D. Allman - JP Morgan Chase & Co, Research Division: And then just in the Marmaton in general, do you think just getting those 700-barrel a day equivalent wells, is that fairly repeatable? Or is the challenge here a little bit more tricky than in, say, Susquehanna County and others?

Well, it's certainly going to be a little bit more challenging in Susquehanna. I think we have illustrated in Susquehanna that we have an area that has shown very consistent results. And the delta between a absolute great, great well to a well that is not as great is much, much narrower than any other play that frankly that I can think about. I don't care where you are, Bakken or Barnett or Permian area. But you have all kinds of deltas between good wells and not-as-good wells. But I do think that the 700-barrel type of well is certainly a well that we do anticipate we're going to be able to drill a lot more of. But certainly, we're not going to be able to predict those today with the database we have as effectively or with as much confidence as we would if we had another 50 wells drilled out there. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Got you. And then just lastly on the Brown Dense, did you learn anything about a better place to lay the lateral or anything you would do different assuming you'll drill another well, I know you said you're not going to drill one this year, but when you do drill your next well?

I'll let Matt Reid to kind of answer that.

Yes. We're still in the early stages around that, Joe. We're still looking at the data. We're looking at some of the pressure data and some of the other information we're gaining from the wells. We think that there's some highly core center wells within the Brown Dense, and we're trying to land our laterals in them. I think half our [indiscernible]. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. And did you have data on the permeability before you drill this first well or...

We did have some data on the Brown Dense permeability, some processes as well. There have been some additional straight wells drilled in there. And we did look at that data and some [indiscernible]. Joseph D. Allman - JP Morgan Chase & Co, Research Division: What was the frac pump rate that you've put on this one?

The rate, we were pumping at 80 barrels per minute, about 8,000 PSI.

The next question comes from Joe Stewart of Citi.

Dan, the 7-mile step-out wells, does that put you in -- is that Harford Township?

No. I think it's in Lennoxville.

In Lennoxville. Okay. All right. And kind of following up on Joe's question about the de-risked acreage in Susquehanna County. When you say de-risk, does that kind of imply that you think approximately 70% of your acreage will produce results basically in line with your 2011 type curve assuming the same number of frac stages?

Well, we have -- certainly in the central portion where we drilled the majority of our well and we started our infrastructure, we feel very comfortable with the consistency yield that we're getting from these wells. And now as we move to the east with the step-out and the results from these wells, we feel good about that. We drilled and seen the information to the west. Even though we haven't drilled a lot of wells to the west, we feel very, very comfortable about that. On the northern fringe of our acreage where we've identified the -- where we're flowing into the Laser line, those particular wells, as they get a little bit shallower, slightly better, we think, are not going to be quite the 11 Bcf type wells that we see in the majority of the rest of our acreage. And we've recognized that as they maybe being 10% of that number.

Yes. Okay. All right. Great. And then on the well cost question, you mentioned the longer lateral well cost. Keeping things kind of -- or making apples-to-apples comparison with 2011, would a 2011 well cost be about $6 million in 2012 though?

That's a good number to use.

Yes. Okay. And then finally, on the Marmaton, given you had a little bit more production history on your belt now, any update to your thinking on potential EURs there?

Yes. We think it's 150, 175, 200, 225, maybe, on the better wells, that kind of the range, a little bit wider range than we normally have because we've seen wider results.

The next question comes from Ray Deacon of Brean Murray. Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division: I was wondering if you could talk a little bit about your investment in this Constitution Pipeline and if that would be incremental to your current takeaway or not.

Yes. Good question, Ray. I'm going to let Jeff Hutton answer that.

Okay. Yes. Constitution is after the hunting season, and it was established to be a 30-inch pipeline and a 121-mile fleet [ph]. Initial cost estimates are, I think Williams' press release just yesterday, around $750 million range. Our participation is at 25% as an owner, and so sometime between now and 2015, our investment will be about 25% of that. Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division: Got it. Got it. And with the -- so would you just add the 1.2 -- I mean, 1.5 Bcf a day to that 600 million a day you gave there? Is that kind of the right way to look at it? Or...

Well, 2 ways to look at it. One is that it’s a 30-inch pipe which is now designed for 650,000 a day of capacity in which Cabot has 500,000 a day of broad [ph] space on the pipeline. Down the road, if it's -- if it merits expansion, then certainly, the 30-inch pipe can be expanded to an excess of 1 Bcf a day of capacity. But right now, we're comfortable with the 500 million a day add, and yes, it is in addition to the current infrastructure plan on takeaway as a 1.5 Bcf. Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division: Got it. Got it. Great. And I guess -- and maybe just to clarify one of the points you made in terms of resource per location kind of across the acreage. So I guess if you were to look at it per stage, just the 11 Bcf wells, so it's about 3/4 of a Bcf per frac stage and maybe to the north if it's 10% less than that. Is that -- based on what you know now, is that fair? Or do you want to see improvement in that?

Well, I think as far as a number in there, I would say it's 7 to 8 Bcf -- I mean, 700,000 to 1 million on production from the wells, EUR, 3/4, that's probably in the ballpark. Also, on the north end of the acreage, on the -- again, the wells that we drilled up there, we think it's probably going to be more on the 5 and 7 Bcf type wells up there. Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division: Got it. Got it. So that's in 15-stage frac type wells?

Yes, correct, yes.

Our next question comes from Marshall Carver of Capital One Southcoast.

Most of my questions have been answered. I did have a couple of final questions though. On the Marcellus, the wells that are at the Upper and Lower Marcellus test, as well as the ones that you're drilling, the down-spacing, so those 500 feet from the nearest current producers. How close are those -- is the upper well and the lower well from each other?

Okay. Marshall, the 2 wells that have gained over 10 Bcf, they're slightly less than 2,000 feet completed in the Marcellus, the Lower Marcellus. We landed the one well right in between those 2 wells in the lower Marcellus, and then we landed the upper Marcellus well at about 500 foot -- or in between, say, the new well we drilled in one of the wells that has cleaned significant production.

Okay. I got you. That makes sense. And then on the Brown Dense, you said you're not actively leasing. Is that because there's not much available near you, ?or is that a sign you're not very encouraged about what you're seeing so far?

Well, there had been a significant land play come through contemporaneous when we were kind of out there. And we picked up a position and felt like when we go into a play, we pick up acreage, and hopefully, we can get in there and make some determination earlier before there is a significant acreage play being made, first-mover type contract. But in this case, there was already a significant acreage play ongoing when we moved up there also. So it just limited and restricted the amount of acreage that we could block up in the area, and our preference is to block up -- so it reduced our additional leasing capacity. The play is still very, very young on results. It's got a large, large geographic footprint, and it's still very, very young with complex -- complexities that you see in every play. And once that data is gathered, we're still making the play as merit.

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

Thanks, Shea. I appreciate again everybody's interest in Cabot. Certainly, as I mentioned, we're going through this soft gas price, anybody's crystal ball, can look into the future and I think has a different date on when we might see additional support from the supply-demand equation. I think it's apparent that the industry is not going to allocate capital to dry gas with the strip that we see. So I think brighter days are ahead. But even though we are in this low gas price and not certainly generating the cash flows we'd all like to see, we are going to be putting significant reserves on our [indiscernible]. We'll have the opportunity to grow those reserves still with a return even at strip prices. So I think we are in a unique position as being looked at as a dry gas player, but at the same time, you are going to continue to see Cabot increase its liquids production. With its every spare dollar we have, we're going to put into the ground where we think we can find oil. So again, appreciate the interest and look forward to the next quarter. Thank you.

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