Reading an online transcription of the SWN 3Q teleconference of Nov. 2, while listening to a replay of the conference, it’s relatively easy to find a number of errors. So I’ve transcribed the Brown Dense portions myself, and posted them below. While I know I removed some errors, I likely added some of my own.

Southwestern Energy 3Q Earnings Teleconference, Nov. 2, 2012.

Note: Only the parts relating to the Brown Dense have been transcribed.

Bill Way, Executive VP and COO, Southwestern Energy (part of opening statement):

Moving on to New Ventures.

We’ve drilled and completed six wells in our Lower Smackover Brown Dense play in southern Arkansas and northern Louisiana. And, as a reminder from our second quarter call, we drilled wells four and five as vertical tests to see if we would encounter the same high pressure that we saw in our third well, the BML. Both vertical tests did encounter this high pressure.

In our fourth well, we tried several different fracture stimulation recipes, primarily involving different combinations of linear gel. And in our fifth well, we completed three vertical stages totaling 12 feet of perforations with white sand and slick water in the sand stages. Production from this well has stabilized at approximately 200 barrels-a-day and 1.2 million cubic feet of gas for the last 10 days.

We’re now using these wells to obtain additional log data and core samples over the formation, and study the effectiveness of different fracture stimulation treatments on the contact area, and to learn more about the fracture height growth.

At a later date, we’ll re-enter these wells and turn them into horizontal wells sometime in 2013.

Our sixth well, the Doles, located in Union Parish, Louisiana, was drilled in September to a vertical depth of 10,673 feet with a 4,700-foot completed horizontal lateral. This well is being completed now, and will begin flowing back shortly. We expect to begin selling both oil and gas from the Doles well and the BML well around the end of November, with the expectation of learning more about the decline characteristics of both wells before year-end.

And I can tell you we remain highly encouraged, and looking forward to learning more on our path to commerciality.

Q&A Period:

Hsulin Peng, Robert W. Baird & Company:

The Brown Dense acreage went down a little bit this quarter, and I’m just wondering if you can help us understand why the acreage number went down?

Steven Mueller, CEO Southwestern Energy:

Sure, and what she's referring to, I think we reported a little over 500,000 acres this quarter versus I think was 540,000 or 550,000 last quarter. The main difference there is on the far northwest corner of the play, there was some acreage that we'd actually acquired from EOG that we let expire, and then we do have some acreage we double counted, but the biggest thing is we dropped some acreage on the far northwest corner.

Charles Meade, Johnson Rice & Company:

I had a question on one of the wells that you talked about in your prepared remarks. I think it was the Dean well in the Brown Dense that you said. Did I get these numbers right? Two hundred barrels-a-day, and 1.2 million out of 12 feet of perfs?

Steven Mueller:

That’s correct.

Charles Mead:

I'm curious, is - did you complete that in a different part of the formation? Is there something, or did you have a different frack design? I know you talked about using linear gels. But the question is, is there something different you did there? Because that looks like a really encouraging rate.
Steven Mueller:

There are some things we did different.

As Bill mentioned in his comments, the two vertical wells we drilled, the first thing we want to do is determine if there was extent to the high pressure area. There was.

But the other thing we found in - and if you remember back to our very first well, one of the issues we had was trying to get enough vertical extent on our fracks. We found as we evaluated the BML well that we still weren't getting the growth in height on our fracks that we were looking for. So we tried several different kinds of fracks in both the Johnson and the Dean wells. And in some cases, they worked, in some they didn't. In the Johnson well, I can tell you two of the five I think we've done so far, we screened out early because the frack that we were trying didn't work. But as we got towards the end of fracking at the Johnson well, we came to what I'll call a new formula, there's nothing magic about it, just kept tweaking. And it looks like we're getting better vertical height.

We tried that on the Dean well and where there's three intervals we fracked, on that well three separate fracks, and the perforations, as he said, weren't much perforations. There's about 200-foot interval. It wasn't anything unusual over any of the other wells in the area. But when you look at the fracture area that it looks like it's, it’s contacted versus even the BML well that has over 4,000 feet, it's got almost 60 percent of the same fracture area. So it looks like we're starting to learn something on the fracture stimulations. And that well has held up very well. The numbers we quoted were on 10/64ths choke, and we still have high 6,000 pounds bottom hole flowing tubing pressure. So, uh, bottom hole pressure. So that well gives us encouragement and we're using a variation of that, for the most part, we're trying some things on the horizontal we're fracking right now. But we're using a slight variation of what we did on the Dean on this horizontal that we're working on now.

So I can't say it's the answer, but I can say that we're getting closer just by working on the fracks, frack stimulation. And it looks like we're getting a little better height than we were in any of the other fracks we've done to date.

Charles Meade:

Got it. That’s all very helpful, Steve. It sounds like – am I right in guessing that it is just a kind of a combination of sand load and pump rate and, you know, some chemistry that you …

Steven Mueller:

It’s just a mix. And when you put the sand in and how much water you put, there’s nothing magical about the fluids themselves.

Charles Meade:

Got it. And then it also looks to me like you guys have set up a unit for the Johnson and Dean to be 1280 [acres]. Is that – are you guys committed to doing long laterals there? Or is that, is that just an option for you at this point?

Steven Mueller:

Just count that as an option right now. I don't know what the ultimate lateral lengths will be. Certainly, if you remember our general game plan was from the first to the later wells, we're going to go from relatively short 3,000-foot and work our ways up to 9,000 feet or 12,000 feet. That's somewhere in the game plan, but if we get some of the encouragement in some other wells like we're seeing in the Dean, it may not need that long a lateral. So we just, we're just going to have to work our way through that.

Charles Meade:

Got it. And just to make sure I understand this right, it’s the Doles that you’re going to complete with this kind of, with your new frack recipe?

Steven Mueller:

Doles is the one that completing right now. It’s almost done. There’s a total – originally went in, wanted to do about 26 stages of frack. I think we’ll get 22 done. And we’re almost done with that, the next couple of days we’ll be done.

Charles Meade:

And that’s using what you’ve learned from the Dean well?

Steven Mueller:

Yes, what we’ve learned from Dean and Johnson and any other wells before it.

Charles Meade:

But the BML is the older version of that frack?

Steven Mueller:

The BML is the first well, as it, it has fracked much more like we did in the first two before it, and there is a significant difference there.

Charles Meade:

That’s great detail. Thank you very much.

Dan McSpirit, BMO Capital Markets:

Folks, good morning. Turning back to the Brown Dense, you speak to a path to commerciality. If you could, share with us the determining factors involved and the expected timing maybe in more definitive answer or color on a go or no-go decision in the Brown Dense. And, in answering that, if you could, share with us the current drilling complete cost for the latest batch of wells and what’s expected going forward.

Steven Mueller:

OK. As you look out into the future, it, there’s – I would put two things that we have to understand. And both of those, we’ll know a lot about in the next three months.

The first one, and we talked about this in the past, we haven’t got a long production line on any of these wells. And so we need to understand the shape of that production curve. We do all of our economics based on an average Eagle Ford because of depth and pressure considerations, but we haven’t got ourselves and average production curve here yet. And we’ll put the two wells that Bill talked about on production this month. We’ll have by January 2-1/2 months of production on those or 2-plus months of production. And when we add that to the testing we had earlier, we’ll be able to figure the shape of those curves.

The other thing we’ve already talked about, you want to contact as much of the rock as you can, and you’re going to have to have vertical height growth on your fracks because you’re looking at a 350 to 400-foot interval. And, frankly, in our first well, we got about 25 to 30-foot height growth. And even in this most recent one I talk about, we’re looking about 90 and 100-foot growth. So we still need to do some things in the fracking side to get across more of the zone and contact more of the reservoir. So we’ll continue to work on the fracking. Whatever we learn in this horizontal we’re doing now, we’ll apply that and go out in the future.

So those are the two main things there.

As far as cost, rather than go in to the various costs in each well, we do something internally where, we call it “pacesetter.” We take the wells that we’ve drilled and whatever the best piece of that well was, whether the vertical part of that hole, whether it’s the horizontal, or building the curve, we’re putting that together and say we can, we know we can do that. And all we have to do is do it consistently, and here’s what’s it going to be. And then from there, we improve, and we go from there. On a pacesetter well - let me just put on days to drill – this most recent well, Doles well, took us about 55 days to drill. A pacesetter well, like I say, one where we just did everything the way we’ve done and had success in the past on each individual portion, would be about a 35-day well for that same well. And when you start talking about 35 to 40-day well, going back to my comments on the second quarter conference call, you’re talking about 10 million to 12 million dollar-type wells. The well we’re on today, on the Doles, is about 12 million dollars, but it’s not significantly above 12. So we’re in the range, and we can see a way to get our costs down.

Let me also add, on the economic side, historically, we’ve talked about the fact that we needed a certain rate, and we threw out any gas. We didn’t worry about any of those kinds of things. But if we can do a 12 million dollar well, to reach our 1.3 PVI – that’s our economic hurdle – we need about 425 barrels-a-day of oil and about 4.2 million-a-day gas when you count that in. That’s $80 oil LLS price, and it is a little over $3 NYMEX price. And you put the BTUs on that, and the oil, and that’s the economics for that.