Greetings, and welcome to Southwestern Energy's Fourth Quarter Earnings Teleconference Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Steve Mueller, President and CEO. Thank you, sir. You may begin.

Good morning, and thank you for joining us. With me today are Greg Kerley, our Chief Financial Officer; and Brad Sylvester, our VP of Investor Relations. If you have not received a copy of yesterday's press release regarding our fourth quarter and year end 2011 results, you can find a copy on our website, www.swn.com. Also, I'd like to point out that many of the comments during the teleconference are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control and are discussed in more detail in the Risk Factors and the Forward-Looking Statements sections of our annual and quarterly filings with the Securities and Exchange Commission. Although we believe these expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may differ materially. Let's begin. 2011 was another record year for Southwestern Energy. We set new records in production reserves and as a result of our 24% production growth, we achieved the highest earnings and cash flow in our company's history. We produced 500 Bcfe, driven largely by our Fayetteville Shale play, where our production grew 25% to 437 Bcf. Our production from Marcellus Shale also grew from 1 Bcf in 2010 to 23 Bcf in 2011, while our Ark-La-Tex production declined from 54 Bcf in 2010 to 40 Bcf in 2011. Our year-end proved reserves also increased by 19% to a record 5.9 trillion cubic feet of gas. Approximately 100% of our reserves were natural gas, and 45% were classified as proved undeveloped. We replaced 299% of our 2011 production at a finding and development cost of $1.31 per Mcfe, including revisions. This, along with our all-in cash cost of $1.27 per Mcfe, give us one of the lowest cost structures in the…

Thank you, Steve, and good morning. As Steve noted, our earnings and cash flow set new records in 2011 as our strong production growth combined with our low cost structure had more than offset the impact of lower gas prices. For the calendar year, we reported net income of $638 million or $1.82 per share, up 6% from the prior year. Our cash flow from operations, before changes in operating assets and liabilities, was up 12% to $1.8 billion. Operating income for our Exploration and Production segment was $825 million compared to $829 million in 2010. For the year, we grew our production to 500 Bcf and realized an average gas price of $4.19 per Mcf, which was down 10% from 2010. We currently have 266 Bcf, or approximately 47% of our 2012 projected natural gas production, hedged through fixed price swaps and collars at a weighted average floor price of $5.16 per Mcf. Our hedge position, combined with the cash flow generated by our midstream gathering business, provides protection on approximately 65% of our total expected cash flow for 2012. Our detailed hedge position is included in our Form 10-K filed earlier this morning. We continue to have one of the lowest cost structures in our industry, with all-in cash operating costs of approximately $1.27 per Mcf in 2011. That includes our LOE, G&A, interest and taxes. Our lease operating expenses per unit of production were $0.84 per Mcf in 2011 compared to $0.83 in 2010. The slight increase was primarily due to increased gathering costs in our Fayetteville Shale play. Our general and administrative expenses per unit of production declined to $0.27 per Mcf in 2011, down from $0.30 in 2010. The decrease was primarily due to the effects of our increased production volumes. Taxes, other than income…

[Operator Instructions] Our first question is from Scott Hanold with RBC Capital Markets.

Steve, can you talk a little bit about the well results in the Smackover play? You indicated that it had low permeability in the lowest most formation, and you're looking to sit the next well up a little bit higher. Can you talk about, just on a relative basis, what kind of perm you actually saw and how the upper members of that is compared? And maybe put it in reference to some other unconventional plays to help us out as well.

Sure. We haven't got all of the information back on the cores for all the permeability. So some of the statements I'm going to make here are generalities from just a little bit of information. But to remind everyone, as we looked at this play going into it, we were looking at, on the low side, 0.1 microdarcies. And then we had as high as 2 or 3 microdarcies-type rock that we were looking at. The core had some very good permeability in the upper part of it. And to put it in a kind of a relative sense, the lower part was on that lower end of the microdarcy range. The upper was almost 5x as good as the lower portion as you looked at it. Now, one of the questions you asked, why did we land in the lower part of the well? If you remember, going into this well, we didn't know what the fractures were going to do, and we were about 500 feet away from a wet zone that we didn't want to fracture into. So we intentionally landed as low as we could in the zone, drilled out the lateral. And then the very first test we did, if you remember, we frac-ed 3 stages and just flowed those back to see if we were getting any unusual water. We weren't. We did microseismic on the 3 stages. We went back, did the other 8 stages for a total 11 stages microseismic on it. And now that we've got the microseismic in, we've seen that -- how we've only extended up our fracs somewhere around 100 to 150 feet above. So we didn't even get into the better rock with the fracs that we did in the first well -- the first zone. So we're excited about having 100 barrels a day coming out of the rock we have. It's some of the lower permeability rock that's out there. It would be the lower end of either the Bakken or Eagle Ford-type rock, and we know that we've got some better rock up above us. The second well in Louisiana, you've got to remember, you're roughly 30 miles away. The actual porosity in it and permeability is thicker than in our first well, and there's some geologic reasons we think that happened in that direction. But we were able to land it in the top half and basically, roughly, the top 1/3. And we drilled much, much faster, and looks much better overall to the point that in the first well, where we had good shows when we were drilling it, the shows we were seeing were just fluorescents. In the second well, we actually had a little bit of free oil on the pit. So both of those have a little bit of difference to them as far as that goes.

Okay, okay, that's good color. And in terms of like -- I guess you had about 1,000 barrels of water load on this one. Where do you expect, I guess, for that second one? Being higher up, it doesn't sound like you're concerned about frac-ing into any kind of water. But what would you expect -- I mean, if you put a stronger frac on this, do you anticipate a better flow rate from the oil? And is there any risk then, being higher up that you're going to frac into the ocean above?

I don't think there's any risk we're going to frac in the ocean because, again, that last frac only extended a couple of 150 feet at the most up. And where we've landed right now, if it extends 150 foot up, it barely gets to the top of the zone. So that's not an issue at all from a frac-ing standpoint. You need to remember, that second well is a 6,500-foot lateral. We will frac it very similar to the first well as far as number of stages per so many feet of lateral. Roughly 400 feet apart on the stages. We will roughly do 3 to 4 perf [ph] intervals before each stage. So we'll end up with over 20 stages of frac on the second well. So even if it was the same quality rock, I would expect to get much better rates. Now the other part of your question was, I think, having to do with how much water should we expect when this is all done. And we don't see, from core analysis, that much water in the formation itself. But that's one of the things we're trying to learn. We don't know what the amount of load water we ultimately have to get back before it's completely cleaned up. We know we're 45% now on the first well. We do know that, as the load water has gone down, it took to the 8th day to see the oil is lower, continues to go down, the well continues to go up. So all of that's still progressing. But there will be a point in here, either on the first well or any of these other wells we drill, where we'll determine how much load water gets left in the formation, how much we can actually get out, and what the ultimate oil versus -- either gas or oil versus water rate is.

And are you going to press release the result of that well? Or are we going to wait to the, I guess, your next quarterly update? Or how is that news flow going to come out?

We don't like press-releasing wells, so my guess is we'll wait until the next time we have something to talk about something else, whether it's end of the quarter or something else we have to talk about.

Our next question comes from the line of Gil Yang with Bank of America Merrill Lynch.

Just to continue along the Brown Dense, can you talk about what you saw in terms of API and sell through for the oil in both -- in all 3 of the wells that you've seen information from so far?

We're looking at mid-30 API, 35, 36 gravity API oil. And that matches with the well tests that were in the area before. If you remember, there's some vertical wells that we had some tests on. And so from that standpoint, oil looks about the same as any of the other ones out there. On the H2S side, we're still trying to get a handle. There are days we get little wisps of H2S. And then other times, we get almost no H2S. But right now, it doesn't look like H2S is significant in any of the wells that we've drilled or where we're at today in the 2 wells. And then we do have a little bit of CO2 that we're seeing in this well. And again, because we haven't got all the water lifted off of it, we don't know if that's going to stay in the well or not, but there's a few parts per million of CO2 as well.

Okay. Have you seen the CO2 in the vertical wells that you looked at?

They didn't report any. And again, those tests went from 1946 to, like, 2 years ago. The only real good information is the ones a couple of years ago, and there weren't any on that. CO2, if you have some kind of reaction at all with the carbonate that's in the formation, CO2 is just one of those things that comes with that. And so as we frac the well, we could have easily had a little bit of CO2 just as a part of that frac process. And once the well cleans up, you may not see CO2. On the other hand, there may be just be a little bit of CO2 with the gas.

Great. And can -- and just a sort of separate question is, can you just talk about the negative revisions on performance in Fayetteville in particular, but both for the 2 areas where you reported that?

Well, I think the easy answer on the whole thing is there's all kinds of things going to the various wells. But the easy answer is it's mainly price, but -- because we're about $0.12 difference from year-over-year. I will say, in the case of the Fayetteville Shale, we took a little bit different approach to how we're doing our reserves this year, and that fine-tuned the whole project for us. And in fine tuning, we had a bunch of wells that were a lot better, and we had a bunch of wells that were a little bit less. And it kind of averaged out to that. So there isn't anything more than that.

Okay. So what you're saying is that the negative revisions were, to a large degree, more -- they're really price revisions, not performance revisions?

Yes. The biggest negative revisions anywhere was in Arkoma and it was one field called the Overton field. And some wells fell out because of price, and then there was just some production revisions there. But like I say, there's not much there, one way or the other, on the revision side.

Our next question comes from the line of Brian Singer with Goldman Sachs.

Two questions, the first is continuing on the Brown Dense. When you look at the lower portion that you did frac into, what are your thoughts on both oil in place, or more importantly, recovery rate? And does the low permeability you saw there, could kick them [ph] up to 1/3 of what you thought was theoretically possible previously?

We're trying to figure that out, Brian. One of the things we do with our first well -- and really, the first, second and third well are all offsetting, within 1 mile or so, some of these vertical tests that we're doing. And at this first well, we offset about 1 mile, 1.5 miles away from another well. It was actually drilled on top of a structure, and that original well was drilled on that structure as well. It looks like that on the top of that structure, geologically, the rock did not -- at least the history of the rock wasn't the same as opposed to the rock that's off the structure. So as you get over towards our well we drilled in Louisiana and some of the other wells around there, that section that has good porosity actually gets thicker. So in our second well, almost 70%, 75% of the section has that high porosity in it, wherein our first well, it was almost 50-50. So as far as oil in place, certainly, the tighter the rock -- doesn't change so much the oil in place, but your recovery will change on that. And we're just going to need some more wells to figure out how variable that is and just to figure out what's going on from there.

And my follow-up is with regards to the Marcellus. Can you just compare and contrast the well results that you're seeing recently in Bradford County versus Susquehanna County?

Well, we don't have any wells yet put on production in Susquehanna County. When we talked about all those wells that we drilled -- we'll see our first Susquehanna wells come on production in sometime in the middle of March. So I can't tell you much about those yet. In Bradford, we have a variance on those wells. I think the best well we have is probably well over 15 Bcf. And we talked about the averages, but I think the lesser of the wells we have out there are probably about a 5 Bcf well in what we've seen. And they're really -- as far as where is better and where is worse, we haven't seen that pattern yet to know exactly that. On the same pad where we drilled 3 wells, it could vary from 6 to the 10 or 12 Bcf range.

Our next question comes from the line of Marshall Carver with Capital One.

Yes, I have a couple of questions on the Fayetteville. You booked 2.4 Bs per well. When I look at that type curve plot that you provide, and you show the curve with the wells over 4,000-foot laterals and almost all the wells you're drilling are 4,000-foot plus, it looks like your wells are tracking over a 3 Bcf type curve, but you're only booking 2.4, and you didn't have many positive revisions. So what should I think about the differences between the type curves you're providing and what you're booking?

I think there's a few things to think about there. First off, when you think about reserves, remember the definition of a proved undeveloped has to be you're 90% certain. So you're going to take your distributions and take a median rather than an average to start with. Secondly, all of those curves that we have in our literature, for the most part, except for just a little bit of drilling last year, were drilled on that mile-apart spacing as we were doing our first wells in the section. And we've always said, as we get to our PUD drilling, what's going to happen is you're going to have 10% -- somewhere around 10% interference in ideal case. So what you need to do is back off of that. And again, if you back off what would be a 3 Bcf well, you get about a 2.7-Bcf well. Now you say you want to be conservative, you're down that 2.4 to 2.5 range as far as that goes. The other thing to keep in mind is you book around where you drilled during the year. And if you remember, we spent a lot of time during the year proving up acreage on what I call the edges of the field. And that's where we've booked our wells as we put the wells out there. So there's a little bit of distribution of wells. We only have around 1,600 wells total booked as far as PUDs. And so there's a little bit of location this year versus some of the other years on it as well that goes into those PUD bookings.

And a follow-up on the -- you all talked about the PV to I [ph] hurdle and not wanting to drill wells that are below the PV to I [ph] hurdle. Is the Fayetteville -- with current gas prices, is the Fayetteville below that hurdle now? And if so, would you potentially reduce activity more if gas stays around $3? Or are you drilling better locations to make sure you hit the hurdle rate? What should we think about that?

What we've done with our 2012 budget, besides cutting back a little bit on the Fayetteville Shale from what we originally announced, we're also changing to the point where we're going to drill the very best wells. And again, in about any of these plays and we just talked about Pennsylvania, you've got distribution of reserves and you've got some very, very good wells, and you've got some lesser wells in there with some kind of average. We've talked about in the past that to drill our average well, we need around $4 price. Well, we have at least a couple of years' worth of wells that we can drill if it stayed $3 flat forever in the Fayetteville Shale, and that's what we're doing. We're drilling those very best wells. May see a little bit of inefficiencies in what we're doing as -- rather than drilling all the wells from a pad at one time, we'll go in and drill the best well off the pad and then move to another one. You'll also see us widen out our spacing a little bit here to make sure that we get better wells. And we'll come back later and put some more in-fill wells into that overall spacing. So we're adjusting our program but certainly, if it's $3 flat forever, we've got wells to get us through this year and into next year, and we're looking for other ones beyond that.

Okay, that's helpful. Do you have a feel for the -- about how much better on average the wells would be that you're drilling this year versus last year in terms of EUR or IP?

Yes. We're going to need those 3 Bcf wells you're talking about. So that's what we're shooting for, to be plus 3 -- plus 3 going on plus 3.5.

Our next question comes from the line of Joe Magner with Macquarie.

Just noticed that the New Ventures budget has dropped meaningfully. Just curious what the underlying drivers or revisions to that budget were. Is that to account for less drilling or reduced expectations around new programs? Just a little more information would be helpful.

What we did was we had put in some dollars for some new plays in the budget and expanding some of the plays we're already working on. And we backed off on that. That's where most of the back-off is. And then we're watching the Brown Dense close, but we assume we would do one less Brown Dense well than we said to prove it up. And we did that on the assumption the industry's going to drill wells around us and to be able to do that. So it's at least one well less and then some acreage. And we'll just look at that and play it out through the year. If we come up with a really good idea, we're not going to slow down picking up that acreage on a good idea, especially if it's an oil idea. But that's where it's at. It's really not changing any of the drilling we want to do this year or the plays that we're getting close to finishing on. It's not affecting those at all.

Okay. And then in the new DJ Basin opportunity, my understanding is that the wells that have been drilled in that Great Plains field were vertical wells. Can you just, I guess, provide a little more information on how you decided to target horizontal in the Morrow section...

And the Marmaton?

Those along with the Marmaton section, and then just kind of what the overall geologic setting is that's being pursued here.

Right. To kind of get everyone in perspective, you hear about Niobrara play. This is deeper than Niobrara. It's in the Pennsylvanian H section. There's Marmaton or Atoka interval, roughly in that 8,000 to 10,000-foot depth range. The field that we talked about, the Great Plains field, is quite a ways away. It's almost 65 miles away from where we're drilling our first well. And as you said, it's drilled and is being developed vertically. And the reason it's being developed vertically is there's over a 2,000-foot section of potential rock interval. And there's in that anywhere from 300 to 700 feet of potential pay that's within the interval. Their best well in that field has -- this was drilled back in 2009. It's already produced 247,000 barrels in 20 months, and it IP-ed at 1,500 barrels a day. That's a 24-hour IP, first 30 days, of 634 barrels a day. So there are some very good wells in that field. There's also some other wells in that field that their 30-day rates were as low as 100 barrels a day. So there's a lot of variability. But therein lies the thought behind doing it vertically versus doing it horizontally. We may end up ultimately having a vertical play here, but we think we've identified a couple of fairly thick zones in our acreage that would lend itself well to horizontals. And if there is a lot of variability in a lateral sense, if we can do it the horizontals, we might be able to streamline some of that range. I've seen Great Plains, where they have 100 barrel a day wells and then they have 1,000 barrel a day wells there. So I don't know what the ultimate answer is going to be, whether it's going to be horizontal or vertical, but we'll start -- that first well will be drilled through the whole section. We'll put a short lateral to see what happens, and specifically in the Marmaton interval. And then that second well is actually planned to be a vertical well. So we're still playing with both of those as we go through. The other thing, just to note, is that while Great Plains field is the closest field to what we're doing, there is 96 wells in the immediate area in southeastern Colorado that have produced out of this section. So it's well known by the industry. It is only in the southern part of the state. And the very north end of our acreage gets on the edge of what would be the Niobrara play. But we really don't have a Niobrara section on our acreage. This is that deeper Pennsylvanian section for anything we're doing.

So this is more like a sort of Texas Panhandle stack wash opportunity?

Some of the sections are almost identical to what's going on in the Panhandle. But yes, that's exactly what it is.

Our next question comes from the line of David Heikkinen with Tudor, Pickering, Holt. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: First question, just thinking about the Lower Smackover Brown Dense. Does the first well confirm or eliminate any acreage?

Not at this point, it doesn't. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And to be clear, the frac -- the water that you're producing is from the frac load, not the reservoir currently?

Yes. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And what percentage of frac load would you expect to be able to recover in kind of -- in that 30-day window? Or do you think it's going to take longer than 30 days now?

Well, it looks like it'll take longer. I don't know. I just don't have a good feel for that. We're continuing -- as you saw, we're still getting 1,000 of barrels a day of fluid back. So it's not cleaned up yet, and it's still giving us frac load back. So I don't know. Is this going to take 45 days or 60 days or 90 days? I just don't know. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And I guess it'd be hard to predict what a stabilized oil rate would be as well, given you...

I can't even start guessing yet. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Exactly. Then thinking on another -- on the midstream, do you have a thought around what the industry-wide gross exit rate would be for this year for your midstream business?

I would say -- and what you're asking me to do is kind of predict what -- besides what we're going to do, predict what the rest of the industry's going to do. I think we're seeing a slowdown in the other industry partners as well. But I haven't heard any exact announcements to know how much it's slowing down. If you step back to October, November time frame, both the other major players, BHP and XTO, were going to actually add rigs. And it looks like they're going to add rigs in areas where we were going to be gathering gas for them. Today, we're getting indications that if there is any rigs added, they're not going to be drilled where we're gathering. So I would guess that, through the year, we'll have a little bit of decline in our third-party gas. Where today it's about 170 million to 180 million a day, it will probably decline some, maybe 150 million during the year. And then we'll be growing our production in the Fayetteville Shale in a double-digit kind of rate. So whatever that comes up, is that 2.3, 2.4 Bcf a day, somewhere in that range, 2.2? I don't know.

[Operator Instructions] Our next question is from the line of Dave Kistler from Simmons & Company. David W. Kistler - Simmons & Company International, Research Division: Real quickly, with the adjustments to the capital budget that took place pretty rapidly here with the fall down in gas prices, how quickly would you look at revising that back upward if gas prices were to start to improve in the second half of the year? And where would you direct your first dollars as you put capital back to work?

I sure hope we come across that situation where it comes up in the second half of the year. But I think -- we're expecting that we're in the price range we're going to be through this year and the next year. The real key for adding anything back is what you think the long-term price is going to be. And so, even if it jumped up for a short period of time at the end of the year, I don't know that, that would make us change our mind. But if we started seeing the fundamentals change so that we could generate something above that $4 range, certainly then you'd see us add. Of the things we have in hand, we really would like to accelerate Pennsylvania no matter what the price range is. But what's limiting us in Pennsylvania right now is our firm capacity, and we're following that curve with the rigs we have. We're working hard on adding more firm, and so you may see us even redirect some more capital in that direction during the year. Certainly, on the New Ventures, if any of those come in -- those are oil, those are different price dependency, you can see us do some things. And in the Fayetteville, we are doing things to get our costs down. And one of the things we're doing is we're going to go into the pumping business, and so we're going to further vertically integrate. We'll have 2 units that we operate in operation by the end of the year. And we should save ourselves about $140,000 per well on the wells that we're drilling with our own pumping equipment. So in that case, as we cut the costs down, then we might be able to add some rigs back…

It will be challenging, and I don't know the exact answer. We have not gone through that calculation. But everyone needs to think about the fact that now that you do reserves on a rolling 12 month average, as we even go into second and third quarters, you're going to start seeing higher numbers last year roll off, and lower numbers this year going into that average. So while year-over-year there was only something like a $0.15 or $0.16 difference in average price, that is going to decrease significantly by the time we get to the summer, just with the first 3 months this year as you go through. So I think all of the industry's going to have some challenges on what they can book and not book. But we haven't done enough analysis to be able to tell you what the issues are going to be. I just know there are issues coming up.

Our next question comes from the line of Robert Christensen with Buckingham Research Associates.

Steve, 2 questions. The first is, can you give us sort of your logic as to where you go in the Lower Smackover? I mean, you started with Roberson, you go to Garrett, BML was chosen third. And just the logic of going around sort of that triangle. Why first? Why second? Why third?

We picked Roberson where we did. We thought it was a little bit -- wasn't quite in the center of the oil window, but close to the center of the oil window. It was offset by some of the best control that we had so we could land the lateral, and we were going to hit the lateral. Again, we don't have 3D out here, so -- but we had a lot of wells that are drilled because they're on top of the structure. We've had a lot of wells that are drilled in Smackover that we could go off of. And then the thought was we move into Louisiana, stay in the oil window and just get a distance away, near another well that had been tested before. And that was what we did at the second well. The third and the fourth wells are similar to that. We'll be offsetting our near wells that have been drilled in the past but spacing ourselves out, just to start seeing the rock characteristics but, for the most part, staying within what we think is the obvious oil window. And then when we originally put the program together for a total of 10 wells, the 6 wells after that, the 2 things we were going to do is start driving costs down on the well themselves. Those first 4 are going to be a lot of science, but then we're going to lessen the science as went through the other ones. And we're going to start pushing the boundaries of the oil window either up dip or down dip. Up dip as you get towards immature oil, and down dip as you get towards the gas part of it. That's all going to change. And really, even our fourth well today is in limbo, exactly where it's going to go. And the reason it's changing is that the industry is also drilling wells. So to the extent that one of those wells we were going to drill somewhere in our sequence are close to one of the industry wells, we're busily making agreements with the industry to trade information. So I can tell you, the first 3 are still under that same logic that we had. But from 4 on, we're revising it as we see other information come in.

And how many wells do you think the company will now drill this year in the Lower Smackover Brown Dense?

I think what we have in the budget right now is 5 wells. 5 wells drilled this year, a total of 6 wells. But we'll drill what we need to drill. And so if the industry gets some more wells down and we could learn the answer without having to drill as many, fine. If we need to drill some more, we'll do that. And we'll just adjust our budget to where it goes. But right now, 6 total is what we're thinking about.

One follow-on, if I may. When you expressed that the oil shows in the second well was actually turning into oil in the pits, how much better, I guess, is the porosity and permeability associated with that statement compared to the statement that we just saw fluorescents in the first well? Can we see quantity through that lens, if you will, that you've offered us?

I think you can start getting indications of quality. As you know, shows have a lot of variables with them: what your mud weight was, what the kind of muds you're using and how fast you're drilling. So there's all kinds of things that go into that. But the second well drilled much faster, was basically the same mud in the first well. That tells you that there was a different rock there and then probably had more porosity and permeability in it. And we did see more oil. So it tends to indicate more permeability. And when I asked our guys that exact same question and pressed them on it, they said, "Well, it looks about 5x better than that lower zone in the first well." Now that's all relative. Is it 5x better, 8x better or 3x better? It's just better. You don't have enough information to know. And we don't have the ability to get chips and -- like you do in conventional, you'd be able to get some chips from downhole, and you'd be able to look at it and compare it. In our case, with the way we're drilling, it's very difficult to get chips. But you have to send it to a lab to even look at the porosity or permeability that's in it. So we've got a core. The core is being analyzed right now and soon, we'll know the difference. But it's all relative at this point in time.

Our next question comes from the line of Dan McSpirit with BMO Capital Markets.

Recognizing the data you're working with is limited and that it's early innings, how does the Brown Dense rank versus the new DJ Basin venture and anything else in the New Ventures portfolio, at least in terms of resource potential and what's economically recoverable?

I can certainly compare the Colorado and Brown Dense. In the case of Colorado, you have had commercial production from that interval, at least in the immediate vicinity of where you're at. And it doesn't have as many tests in the area. There's only 4 wells, within the area we're buying acreage, that have gone into that zone. But it did have shows and those kinds of things on it. But since you have commercial production, I think the real issue in Colorado is the variability of the rock, and can you get consistent commercial production? In the case of the Brown Dense, Brown Dense is much bigger. We've got 238,000 acres in Colorado, and that will grow some, but it will be in the 250, 260 range. In the case of Brown Dense, you've got over 500,000 acres in roughly the same thickness objective interval. They're spaced out differently, but roughly the same. So the Brown Dense has a lot more in place to go after, but it's going to take a lot more to figure it out too, because it's a bigger area. So going into the Brown Dense, we had really 3 big issues: How to drill. When you frac, will you get into the water that's above it? You don't have that problem in Colorado. And then can we make it commercial? We know we can drill it now. The second well drilled much, much faster. Third well, we're blowing that one down. We're getting the pace done. We think we know where to land in the Brown Dense, but we still have to figure out commercial there. So that's kind of the differences.

Okay. And then a follow-up on the Brown Dense itself and, specifically, the Union Parish well. How does the rock change moving west to east? How does the risk profile change, that is? And how will that well be completed? Will it be completed any differently than the first 2?

We're still looking exactly on how the well is frac-ed. But basically, it will be completed the same. It'll just have more fracture stages because it's a longer lateral. And the third well, by the way, we're going to try and do that. That's in Louisiana also. That's going to be a 9,000-foot lateral, so that's even going to have more stages in it. But right now, we'll frac them basically the same, with just minor variations, just to see the differences. So we can really tell the difference in what's going on with the rock, not the difference in how we're frac-ing them to start with here. As far as the way it looks in the rock, it's a little bit thicker as you go to the east. So it's probably 75 to 100 foot thicker in general in our second well than in the first well. And again, that first well was over 350-foot thick. So it's a very thick interval. When you look at a log that's drilled through it, there's distinct log characteristics that we're trying -- we think we figured now that shows the better-porosity rock versus the tighter rock. And we're in the early stages of understanding this. So I want to emphasize that we think we're getting to understand it. But if we're understanding it right, certainly, the logs are about 2x as thick for the good interval in the second well than they are for the first one. But again, second well, we've got a core in and analyzing right now. First well, we haven't got all the permeabilities back on it, so we still got some things to look at before I can pound the table and say it's definitely getting better in one direction or another. We do know, if you go far west, if you go over towards the Louisiana/Texas line, you're getting deeper. The rock is higher temperature, more cooked, and you get into gas. So in general, the oil window is going to swing around from the Arkansas down into the Louisiana in general.

[Operator Instructions] Our next question is a follow-up question from Scott Hanold with RBC Capital Markets.

Either -- Steve, you mentioned about investing in some pressure pumping. What are the plans there? I mean, how much horsepower are you looking to add? And what's the CapEx on that spend this year?

We will basically do 2 frac spreads. And I don't know it off the top of my head, the exact horsepower. Total investment will be probably about $65 million for the 2 frac spreads. And we'll have them operational, hopefully, in November time frame of this year. So it's really a cost saving for next year. As far as the capital budget, in the original capital budget, we had put $50 million in, thinking the frac spreads would be done in early 2013. We count it as capital. In this one, with reduction of the $200 million, we've taken it completely out, and we're going to finance that through leasing. So it's not a capital item right now as the way the budget sits.

Okay, so it's not on your budget. It's a leaseback.

Correct.

Okay. And then can you talk about the Fayetteville recovery now? So are you running 11 rigs now and there has been plans to drop one? And then is 2 others coming off? Can you kind of give us the timing of that? Or tell me if I got that right?

We're working on that. There's 11 today. One will drop in the next week or 2. Then what I think you'll see between now and sometime in July, we'll drop 3 more at least, and possibly 4 more rigs. I say 3 more -- 3 more from the 10 going down to 7, 4 total rigs from where we're at today. And we're still trying to get the finals on that, so we may run one rig a little bit longer as we look at it. But that's roughly what we're going to do: exit the year running 7 big rigs in the Fayetteville Shale.

Okay. And would production at Fayetteville grow at that point? Or would it be fairly flat?

It will grow through this year. If you continue running 7 rigs into the future, it flattens out pretty fast.

Our next question is a follow-up question from Robert Christensen with Buckingham Research.

The fourth well, I thought, was back up in Arkansas. Was that the case? Or...

That's the way it has been planned. Yes.

And the follow-on would be, if the...

And let me add one thing in there, Bob. On the fourth well, originally, it was planned to be very close to our Cabot, just recently drilled well. So as long as we can get information from Cabot, if it's in Arkansas, it won't be where we originally planned it. I can tell you that. So we're still looking at that.

All right. And if the formation thickens up enough as you go further to the east, would it ever make sense to maybe drill just a vertical well and fracture stimulate that first as opposed to going horizontal from the get-go?

Yes, we don't think that, that will work. But we need to get some confirmation back. I won't say you'd never do it that way, but when you just look at the advantages -- in that second well, it took us about 14 days to drill that 6,600-foot lateral that's out there. I know we can decrease that time. And if you're down at 10,000 feet, you might as well take the few days extra it takes to drill the lateral and then add the fracs and get the added advantage to that. But we'll certainly look at it, just like we'd look in Colorado, which is the best way to do it, vertical or horizontal?

So the second well, what was the total time to drill? Because you're in vertical for -- on that?

Roughly 50 days, give or take. I don't remember if it's 50, 53, something like that.

50 days, all in, for the second well. And what's the rough cost on the difference between the first well and the second well, would you estimate? I mean, is it a big step up or about the same?

The first -- all of these wells -- the first 4 that are going to do the core and all the science would be above $10 million. The first well, we actually got out -- I don't remember if it was quite 2,000 feet -- and wasn't where we wanted it to be. It had some problems with the well and backed up and rigged it to sidetrack. So that first well is probably $2 million -- $1.5 million to $2 million higher than the second well, just on redrilling the lateral. But ultimately, we think we can get these down in the $7 million to $8 million range, is what we're shooting for.

Do you think the second well is going to be more costly than the first well?

No, no. So even some will be cheaper than the first well by about $2 million at least.

Our next question is a follow-up question from Gil Yang with Bank of America.

Steve, you mentioned that you're going to drill, I think, a couple of stratigraphic vertical tests in New Brunswick. Can you just comment on sort of what you're looking for in those kinds of wells, what we should expect you to learn from those wells?

Sure. In New Brunswick, we need to get this other seismic shot. But if you think about the sequence we've done, we think we've found a new basin. We did a bunch of work to prove it was there. We shot seismic -- maybe a little bit more seismic done to the east that we didn't get done in 2011. And the whole idea was to identify where the basin deeps were, where the -- if you spot any highs, and then pick a couple of wells. They could tell you actually what's in the basin. At this point in time, you've got rock that comes to the surface north of where the basin's at. You've got a basin to the south that's got some wells in it. But these basins have no wells whatsoever. So at least one of those stratigraphic tests will be in one of the deepest parts in one of those basins. You just drill right through the whole interval to try and figure out what's there. Is the shale -- further [ph] scored shale there or not? Is there any conventional targets that are possibly there? So you just look at the section. The second well, depending on exactly where you're at, may have some other target to it, where you've seen something on the seismic that you want to investigate. But both of them basically are just trying to figure out what the section looks like so you can tie in more data. So later, you can then come back and actually drill wells that would have hydrocarbons as the objectives.

Okay. So it's basically to provide the subsurface data that ties you to the different horizons you're seeing on the seismic?

Right, right. And then just to give you an example, while you see events on the seismic, you're just guessing at what the velocity is or what the depth is, because you haven't got any data to tie it to. You're just -- and the nearest data is 60, 70 miles away. So that first well will just let you tie that in. It will let you figure out how to redefine your gravity and magnetic situ work on the basin. So you'll get that information, redefine everything again, and then you'll actually start drilling for true objectives.

Great. And another follow-up. I think in your previous budget, you'd set it at $4 a gas, and you were very good in giving sort of the guidance based on -- sensitivity based on different commodity price assumptions. And it looks like the current budget based on that is -- announced spend of maybe $400 million, $500 million based on $3 a gas. Is that a fair assumption as to what you're pricing in, in this budget?

It's in that range. I don't know if it's quite to the $500 million range, but it's in that range.

Right. But the base assumption is you're sort of assuming $3 gas?

Yes.

Our next question is a follow-up question from Joe Magner with Macquarie.

Just one quick follow-up. You mentioned that you had taken $65 million out of the budget for spending on the pressure pumping equipment. Which bucket did that come out of? It doesn't look like there was an obvious drop in midstream or other. Just curious where that might have shown up prior.

That was actually in the Fayetteville Shale. And it was about $50 million. Again, we thought we weren't going to get the equipment till early next year. Now we're much more comfortable we'll get the equipment this year. So $60 million was -- total of $50 million was actually in our budget.

Ladies and gentlemen, we have reached the end of the question-and-answer session. I would now like to turn the floor back over to management for closing comments.

Thank you. We've had a lot of discussion today about the Brown Dense. I had some discussion about Colorado. But what I want to leave you with is we're very proud of what happened in 2011, and we especially want to thank all of our employees who have done a great job. When you think about the Fayetteville and Marcellus, I wouldn't want any other assets in today's price environment. We know we can overcome the challenges of those assets as we look out into 2012 and even as we look out into 2013. We know we can deliver for shareholders in those events. And then we're really excited about 2012. Brown Dense, first well, a lot of questions answered. A lot of questions asked. We're getting ready to drill in Colorado. I'm sure that will be the exact same thing where those first few wells will be asking as many questions as we answer them. But these are quality plays, and they're the kind of things to expect from us as we look out into the future. We've got New Brunswick coming up, and then we're still working on some other projects. There's still some other acreage we haven't talked about out there. So we're really excited about 2012. This is a year for us to thrive. This is a year, irrespective of what gas price is doing, irrespective of what the oil price is doing, irrespective to costs, that we think we can deliver for shareholders, and we're just looking forward to updating you in the future on that. So thank you, and this concludes the conference.

Ladies and gentlemen, this does conclude today's teleconference. You may disconnect your lines at this time. Thank you for your participation. Have a wonderful day.