西南能源 (SWN) 2011 Q3 法說會逐字稿

Greetings. Welcome to the Southwestern Energy third quarter conference call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation.

(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, Mr. Mueller -- you may now begin.

Thank you. Good morning and thank you all for joining us. With me today are Bill Way, our new Chief Operating Officer; Greg Kerley, our CFO; and Brad Sylvester, VP of Investor Relations.

If you have not received a copy of yesterday's press release regarding our third-quarter 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 this 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 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.

To begin, we posted outstanding results for the third quarter. Our earnings and cash flow were up, primarily driven by production growth, which continues to exceed our expectations. As a result, we have increased our production guidance for the fourth quarter and for the full-year 2011. Total production growth was 23% during the quarter, fueled by our Fayetteville Shale, which grew 21% with production of 112 Bcf. We also produced 7.4 Bcf from Marcellus Shale, and 9.6 Bcf from our Ark-La-Tex Division.

Now, I'm going to talk about each of our operating areas. We placed 132 operated wells on production in the Fayetteville Shale during the third quarter, which resulted in gross operated production reaching approximately 1.9 Bcf per day earlier this week. Overall, our operated horizontal wells, on an average completed well cost of $2.8 million per well, with an average lateral length of 4,847 feet and an average drilling time of 7.8 days, during the third quarter. We also placed 25 wells in production during the quarter that were drilled in 5 days or less. In total, we have drilled 80 wells to date in 5 days or less.

Our average initial producing rates were approximately 3.4 million cubic feet per day, which is up 14% from the second quarter. In the Northeast Pennsylvania, we're very encouraged by what we have seen. No new wells were placed on production in third quarter; however, we are excited that the same 17 Marcellus Shale horizontal wells in our Greenzweig area in Bradford County are currently producing approximately 110 million cubic feet of gross operated production per day, compared to 104 million cubic feet per day when we spoke to you at the last teleconference. Net production from the area was 7.4 Bcf in the third quarter of 2011, compared to 5.1 Bcf in the second quarter.

As for activities for the rest of the year, we are currently in the process of completing our 5-well pad in Bradford County, and expect those wells to come online in November. We have also moved in a second rig and started drilling our Price area in Susquehanna County, and we expect to have first production from this area in January. We will be drilling in Greenzweig Price and Range Trust areas throughout the rest of the year, but we will not put any new wells to sales until January due to state permitting delays, and the constraints of firm transportation and gathering capacity. We're planning to be much more active in the Northeast Pennsylvania in 2012, and have recently signed a contract for 2 additional rigs to be delivered in mid-year 2012. These rigs will be newbuilds and designed specifically for our Marcellus Shale operations.

Switching to new ventures -- in New Brunswick, we completed a second phase of surface geochemical sampling, and the acquisition phase of approximate 250 miles of 2D data; interpretation of both sets of data is currently under way. The next step in 2012 is shoot more 2D seismic to help give us a better understanding of where to drill our first well. Outside of New Brunswick, we currently have approximately 948,000 net undeveloped acres in connection with other new venture prospects. Of these 948,000 net acres, we have approximate 487,000 net acres located in the Lower Smackover Brown Dense formation, an unconventional oil reservoir found in southern Arkansas and northern Louisiana. We started our first well in September, the Roberson 1-15H, located in Columbia County, Arkansas, and is currently drilling a lateral portion of the well. This well has a vertical depth of approximately 9,200 feet, and a planned horizontal lateral length of 4,000 feet, and is planned to be completed next month.

We will spud our second well, located in Claiborne Parish, Louisiana, as soon as the rig moves off the Roberson well. This well has a planned total vertical depth of approximately 10,700 feet, and a planned 7,900-foot horizontal lateral. Our plans are to drill up to 8 additional wells, as we continue to test the concept in 2012. If our drilling program yields positive results, activity in the [Claiborne] can increase significantly over the next several years. In addition to the projects mentioned, we have 461,000 net acres on other [ideas] that we will provide updates on in the future. This acreage total is 86,000 acres, up from second quarter, or 23%.

I will now turn it over to Greg Kerley, our Chief Financial Officer, who will discuss our financial results.

Thank you, Steve, and good morning.

We reported earnings for the third quarter of $175 million, or $0.50 a share; up 9% from the prior year. Our discretionary cash flow was $473 million; we set a new record, and was up 12% from the same period in 2010. As Steve noted, our earnings and cash flow were up, primarily due to our strong production growth; which, combined with our low cost structure, more than offset the impact of lower gas prices. Our production growth continues to exceed our expectations, and as a result, we've increased our production guidance for the full year to 496 Bcf to 500 Bcf equivalent, representing an increase of approximate 23% over the prior year.

We realized an average gas price of $4.30 per Mcf in the third quarter, down from $4.67 a year ago. Our hedging activities helped to increase our average gas price by $0.59 per Mcf during the third quarter, and for the remainder of 2011, we currently have NYMEX price hedges in place on notional volumes of 80 Bcf, which is over 60% of our expected fourth-quarter gas production, at a weighted average floor price of $5.21 per Mcf. Operating income for E&P segment was $229 million during the quarter, compared to $217 million in the same period last year. Our cost structure continues to be a key advantage for us, and our all-in cash operating costs, which includes -- lease operating expenses, G&A, taxes other than income tax, and net interest expense -- were $1.26 per Mcf in the third quarter, down from $1.31 per Mcf a year ago.

Our full cost pool amortization rate also declined to $1.28 per Mcf in the third quarter, down from $1.31 per Mcf in the prior year. Operating income for our Midstream Services segment was $67 million in the third quarter, up 25% from the prior year. The increase in operating income was primarily due to the increase in gathering revenues from our Fayetteville and Marcellus Shale properties, partially offset by increased operating costs and expenses. Our Fayetteville gathering system achieved a significant milestone during the third quarter, as the system throughput exceeded 2 billion cubic feet of natural gas per day, up from 1.7 billion cubic feet a year ago. As a reminder, in the Marcellus, we currently have firm transportation agreements in place on approximately 125 million cubic feet of gas per day. Our firm transportation increase is roughly 155 million cubic feet per day in the first quarter of 2012, then increases of 215 million in the second quarter and a 300 million in the fourth quarter of 2012.

At September 30, we had $600 million borrowed on our $1.5 billion credit facility, at an average interest rate of around 2.2%; and had total debt outstanding of $1.3 billion, resulting in a debt-to-book capital ratio of 26%, which is down from 27% at December 31, 2010. More importantly, our cash flow in the third quarter exceeded our capital investments for the first time since announcing the Fayetteville Shale project seven years ago. We continue to borrow some funds at times to drill efficiently and test new ideas, but this is yet another milestone in 2011, along with gathering over 2 billion cubic feet per day and almost 100% pad drilling in the Fayetteville.

In summary, we are very pleased with our third quarter results and the progress we've made year-to-date. Our strong operating and financial results continue to reflect the high quality of our assets and cost structure. We are well-positioned to provide profitable growth in production and reserves over the next several years.

That concludes my comments, and I will turn back to the operator who will explain the procedure for asking questions.

(Operator Instructions)

Brian Singer with Goldman Sachs.

Hi, thanks. I wanted to focus on the Marcellus Shale with some of the very strong well results that you had in your -- in the chart. Can you just talk to where you think these wells would be producing on an unconstrained basis were it not for any of the pipeline issues? How you think about how those wells and how the well results will start to move around as you start to drill more in Susquehanna County?

There's really a couple of things to think about as far as the wells. If you remember, last quarter, we talked all the wells were flowing against about 1,100 pounds pressure. We had not turned compression on. Today, we do have compression turned on for most of those wells and we are flowing basically against something in the mid 400-pound range. Now that compares to say, Fayetteville Shale, we are flowing against 100 pounds so it's still more than is ultimately typical, but that does constrain to some degree.

The other part if you look at those curves that we have, you see that our production has been brought up fairly slowly. We have not, in any of the wells, brought them on quickly. We've slowly ramped them up and we've capped them, I think the best we have ever done is somewhere around 10 million cubic feet a day.

What could be their ultimate? You can do some back-of-the-envelope calculations and on an IP, if you brought it on fairly quickly, went to compression immediately, you might have between 25% and 30% to that -- whether it's a 6 million a day well or 10 million a day well type numbers, so that's the range.

Now as we go forward, I think you'll see us do a couple of things. The lateral lengths will get a little bit longer. It looks like and we are still working on this but it looks like more stages of fracture are better than fewer stages, and today, we're -- I think, averaging about 10 stages to 11 stages of fracs. You will see that go up a little bit. So at least in this Greenzweig area where we have information, I would expect that the future wells would be the same kind or if not, a little bit better as we go through.

Great, thank you. And then a follow-up question would be just on the midstream side of the equation. Can you just give us your latest thoughts on the strategic importance and various options you may or may not be considering?

I think you're talking about Fayetteville Shale there?

Yes, yes, switching to the Fayetteville midstream.

I'll mention some on the Marcellus also but really no change in what we were thinking before where we still are open to do something, but it is probably not the right time right now. When I say it is not the right time, we are working on 2012 budgets to figure out how much capital we may need in 2012. That's not done yet.

And as we look at the market, there's nothing that says you have to do it today versus maybe waiting a quarter or something so we keep watching it. There's value in our midstream. There's value in keeping our midstream where it is at and there's possibly value down the road to doing something with it also.

Now I do want to mention something on Marcellus, and it is related to how we look at our midstream. Our midstream is a standalone group. It is -- we sign contracts with our midstream in all of the areas where they gather. And we actually have them bid just like they were another company whenever we are working with them.

In the Marcellus, the one deal we have now is a company called DTE, they will be putting in part of our gathering system because the bid, frankly, from our midstream wasn't as good. So we've got some of the Greenzweig area that's being gathered by our midstream. We will have some of the other parts of it gathered by other companies and so there will be a mix in Pennsylvania.

So your decision as to whether you would move ahead with it, selling an interest or moving to a different corporate structure with the midstream would be based on your having a specific plan of action on investing the cash? Or is there anything strategic that needs to change in the Fayetteville itself?

The Fayetteville capital is dropping this year versus last year and I think you'll see it drop in 2012 and the reason for that is we do have the backbone in. And we've always said that, that was the biggest part of what we needed to do.

There are some things in the Fayetteville, especially with some third-party gas that we'd like to get taken care of, that might give some more upside to the midstream. But by far the dominant thing is, if you're going to bring in cash from any direction whether it is midstream or selling an asset, or going to the market and raising it, we want to have a good reason to put that cash to work that we can ensure all of our investors that it makes more sense putting cash to work there than it is putting it someplace else. So that's going to be the key on any of it; it doesn't matter if it is disposition or midstream.

Thank you very much.

David Heikkinen with Tudor, Pickering.

Good morning Steve, just thinking about multi-year plans in the Marcellus and where your constraints are today on the pipeline systems and where things go over the next several years. Can you walk us through an overall marketing plan, both transportation on the pipelines to market as well as the midstream as you march up activity levels beyond 2012? And just how you're thinking about where those limits and governors come in?

There's two pieces of that; Greg will give you some guidance on what we've got firm for 2012. When you look at 2013, as you exit 2012, we've got about 300 million a day of firm capacity. Through most of 2013, we have 300 million a day capacity. And then right in the fourth quarter of 2013, that jumps up to somewhere around just a little bit short of 490 million a day. That's all firm that we've got in hand today.

We are working on other firm and there's some little gaps in there as we start looking at curves and we have to fill in some things between now and 2013. And we think there's some small -- when I say small, maybe 25 million a day to 50 million a day pieces that we can fill between now and 2013.

As you look beyond 2013, most of the projects that are on pipes that's currently in the Marcellus have been prescribed by the various companies that are out there. And so there's not a lot of firms to get beyond little pieces. So what you have to do is have new pipe into the area. And I don't -- except for knowing that we have to have new pipe in the area, talking to several different groups that have proposed where that pipe might go in and how it might work. That's where we are at in that process.

But at 2013, we've got just under 500 million a day. The shortest contract we have for firm is 10 years, most of these are 15 years and there's one 20 years in there. So, we've got at least that for 2013 forward.

From a rig count standpoint, That's really the way we're designing our rigs also. We've got 2 rigs running right now. We said we're going to add 2 rigs next year, Somewhere between 4 rigs and 5 rigs gets you in that range that we are talking about with what we have firm today. So you won't see us ramp up much more than that without having some other firm in hand.

Okay. And as you think about the evolution of the Marcellus and your overall portfolio and in the gas market, how does this change your thoughts around how you market or where Fayetteville gas goes? I mean, do think it has an impact just basin-wide, not just Southwestern production but what is this -- I mean the reservoir's remarkable, so how do you think about that impact?

I think we're like everyone else, we are try to figure out how fast it's going to grow and how big that impact really is for the Northeast and for the rest of the country. You're starting to see some of these contracts that actually have backhaul where they're either backhauling back towards Chicago or backhauling down to the Gulf Coast. Until we get more built into the system, the system will limit how much you've got and that will put a moderator at least for the next few years on having the issues. But as we start building out beyond 2013 as an industry, we'll have to go some other place in the Northeast.

Now how does that factor into, for instance, Fayetteville Shale? We always set the Fayetteville Shale up, knowing that we'd be there for a long time, And that over time we had no idea where the best place to sell gas was.

So if you remember, the way we designed it, we have the ability to send about 2 BCF a day either to the East Coast or to the Southeast. And then we've got the ability to send probably our pushing about a BCF a day to the mid-continent, whether that's to the Gulf Coast area or up to Chicago. Our idea all along was that over the years at certain points of time, you'd put gas one way or the other in the system.

So that's our strategy, really, for any areas, Try to get as much as you can to as many markets as you can so that, as it evolves over time you can take advantage of that. The Northeast is much harder because, frankly, you're in the Northeast. We're not going to get that gas to the West Coast and it does cost quite a bit to get to the Gulf Coast. So it is something for the entire industry to look at.

Okays. Thanks, guys.

Scott Hanold, RBC Capital Markets.

Steve, could you give us your view on what you think of gas price at this point in time and structurally, what could that mean to Fayetteville activity? I mean, we've been stuck in this $4 range for some time. How do you think about that when you develop your plans on the Fayetteville going forward?

I think, internally, $4.50 is the new $7 is the way we think about it. There is a lot of gas out there. Certainly, you see indications on rig count when it drops below $4 and stays there for a few months if the rig count is affected. But anything above $4, rig count seems to be holding pretty much where it is at today.

So we are just assuming for the next few years, at least, that we're range bound in that $4 to $5 range. And I think that you've -- it is reflected in our hedges. As Greg said, we've got 60% of our production hedged at $5 this year just to guarantee that our realized price will be above $4. Then as we look out in 2012 and 2013, we've got 266 BCF hits in 2012 with like $5.16 floors, we've got 185 BCF in 2013 with $5.06 floors. That, pretty much, will guarantee unless gaskets in the low $3 that we'll be in the $4 price environment.

As we've mentioned in the past, that our key project, Fayetteville Shale, as long as we can get $4 flat, we hit our 1.3 PVI hurdle and can stay close to cash flow and all those other neat things we need to do. So we are planning it will be in this environment and I think we've got hedges for next couple of years of what -- already pretty much tell us that we can stay in that environment. We will when we get the opportunity to put more hedges. We are not done there and we are hoping for some cold spots during some of the winter is coming up so we can do that.

Okay, so activity in the Fayetteville Shale will be served steady state here over the next couple of years in this environment?

Yes, I would say at least steady state. But if everyone -- to remind everyone, they way we designed our Fayetteville Shale this year, we designed it to basically attempt to live within cash flow. And as it -- production grows, as long as the price, gas price stays in this environment, it will continue to give us excess cash flow. You might even see this thing creep up a little bit in our drilling. We've got a lot of wells to do there so that's the other moderator we put on Fayetteville Shale.

Okay, understood, and for my follow-up, on the Smackover play. Obviously you are still drilling the wells so you probably have not much to offer on what you are seeing yet. But what should we expect in terms of information coming from Southwestern on that well result? It sounds like this could be a December-type of event and are we -- what should we expect? Is it IP rate or some extended flow rate test or what things do you plan on talking about?

As far as what we know today, we did take about 360 feet of core, got all of it about 10 feet of core, so we got a very good sampling of the entire interval with our cores. That's all in labs, being looked at in various, different ways. But the first indication and again, to remind everyone, we were offsetting a well about a mile away that had a test on it and was cored.

We didn't have the core to look at it but we had some core data and everything we are seeing in the core to date looks like the core about a mile away so is confirming what we thought, even to the point where you can sometimes get indication whether there's oil or gas. This looks oily from what we are seeing in the core So that's where we at as far as new information.

Then as we look forward, what we are thinking about today; and it is a little bit different than what we are thinking in the second quarter. Second quarter, we thought we would complete the entire well, do all the stages of fracs in mid-November and certainly by December or early January, have enough production data we could talk about the entire well.

What we are talking -- what we're thinking about doing today and it is not completely finalized, but what we are setting forth today is basically splitting the oil in half, completing part of it with one sets of stages between first, and now the first -- both the stages and the first is a little bit different. And then producing it for awhile, coming back and completing the second half. If we do that then you will get some information late in the year on part of the well and how it is produced but you won't get the whole well until after the first of the year.

We haven't quite finalized that so I can't guarantee it. But I think two things to say -- once we get information you won't see us press release probably but the second we get a chance to either do quarterly data or year-end data or have a conference call, we will talk about with whatever we got on any wells that are out there.

And under the rules, especially in Arkansas, we have to put that data quickly to the state if you want to sell anything that came out of that well so the state will also have the information fairly quickly. So we -- there's nothing confidential necessarily about the well test data or what we are seeing in the wells.

Can you tell me what -- you said you're going to split the well. Why would you do that?

We did this in the -- early on in some of our wells in Marcellus where -- you don't know a lot of things. You don't know what the right frac fluid is; you don't know what the right spacing to put the fracs in the well is; and you don't know what the right spacing to put the perforations in the well. So one of the ways we've got up to speed quickly in the Marcellus was, in our first few wells and say the toe, we put the perforations at one spacing and the heel of the well, we would put another spacing. And we tested two different parts and so we could basically get information that would normally take you 2 wells to get in 1 well.

We are talking about doing that same thing in this well where the fluid will be the same, the amount of sand we put in general per frac will be the same. But we might change the spacing of the fracs or we might change the spacing of the perforations just to see if there's a difference in how it produced to help us set up to how to complete the next well. So it just accelerating our knowledge by trying to figure out some of the little tweaks early on.

Okay. Understood. Thanks.

Amir Arif, Stifel Nicolaus.

Thanks, good morning guys. Steve, the question was on your second Smackover well; you're going to do an 8,000-foot lateral, almost doubling the lateral length of your first well. So I was just curious, is this related to what you were just talking about in terms of being able to test different things or is that a comfort level with going ahead and starting to do longer laterals in terms of the productive potential of the horizon?

It is both. We want to see what a longer lateral would do and certainly, a longer lateral gives you more ways to test it. But the other thing is that there's a difference between Arkansas and Louisiana.

Arkansas, under current rules, you can -- you need to keep your well within a square mile, 640-acre section. So if you're drilling either north-south or east-west, you can only have about a 4,000-foot lateral. In Louisiana, you can put up to a 1280-acre unit together and then you can drill a lot longer lateral.

So one of the reasons for doing the Louisiana is because we can drill a longer lateral to test some of these things, but the other part of it is if the state rule lets you do it there. I expect that once we figure out what the right lateral length is, if it is not correct in Arkansas, we'll go back, just like we did in the Fayetteville Shale and be able to change some rules to make it the right length. But right now, the maximum lateral length in Arkansas is somewhere around 4,500 feet.

Okay. Thanks and then just a second question on the Fayetteville side. Your drilling efficiencies keep getting better in terms of days to drill so as you look at your 2012 budget, are you thinking about keeping the similar number of rigs. So 12 rigs running even if you're going to drill a lot more wells if your drilling days drop down? Or are you thinking of keeping a constant number of wells and maybe moving 1 of the rigs to Marcellus or somewhere else?

That's a good question and I don't have an answer. We've got some meetings next week that can help us with that.

We just have to look at where the capital is going and how the overall capital looks to figure out rig counts at wherever we are at. But if I had my preference, we'd probably just keep the rigs the same and let the well count creep up a little bit But that decision is still to be made.

And the detailed 2012 guidance, will that come out in December or January?

Historically, sometime towards the middle of December, we do something that talks about end of the year and 2012 numbers. And unless there's something just really unusual, I would expect the same thing would happen this year.

Thank you.

Thank you. Scott Wilmouth, Simmons and Company.

Hi guys. 15% of the budget this year is going to Marcellus. I know it's stepping up next year. Do we have any early indications of what that allocation percentage might be next year for the Marcellus?

And then what are current well costs running in the Marcellus?

I don't know about a percentage of budget, I can tell you that whether it's Marcellus or Fayetteville, it is a little bit more expensive to run a rig in the Marcellus, but it is around $100 million per rig per year to drill and complete wells. So when we talk about adding 2 rigs in the middle of the year, that's equivalent to 1 running all year so that's $100 million, a little over $100 million of additional budget over the 2 rigs we are running now. So you can start factoring in some dollars on that side.

As far as our well costs go, it -- I don't know yet what a typical well is going to be, but the average that we've done today is just under 10 fracs per well, and just over 4,000-foot lateral links. Those are running about $5.5 million to drill. The 1 well that we had the 19 stage frac on, we talked about last conference call, was almost $8 million well in that case. So that's the range that we are looking at.

Okay, thanks and then just following on some Fayetteville efficiencies. Obviously, days to drill ticking down a large number of wells, I think 25 wells under five days, and I think the limiting factor there using a one bit. What can we expect for that going into 2012? Are you guys seeing something that you think you're going to be able to do this more frequently?

I did a quick calculation, 19% of our wells last quarter were under five days, so that's significantly higher than it's been for any other quarter. It's creeping up; it is one of those learning curves. We're trying to figure out where that might end up as we go out into 2012.

Certainly, all indications that I have is, this year we guided that we'd average nine days and we missed badly. We are going to average in mid-8 days or even though low 8 days this year. Next year, you'll see some average number less than 8 days per well.

Okay, thanks guys.

Thank you. Gil Yang with Bank of America.

Good morning, Steve. Could you comment on -- it looks like the number of wells you're putting on per quarter has been dropping. Is there anything in particular going on there?

No, just how many wells were drilled. If you think about the third quarter versus the second quarter and you're talking about Fayetteville Shale. We moved 2 rigs from the Fayetteville Shale -- 1 rig late first quarter, 1 rig late second quarter and then 1 rig -- yes, late second quarter and then 1 rig in first quarter up to the Marcellus. And then we had to pick up 2 outside rigs. And so there's about a 1.5 weeks', 2 weeks' worth of time where we weren't drilling with the same number of rigs. So we were down a little bit on well count.

We are actually, on number of wells and inventory, almost identical quarter-over-quarter. We usually have about 50 wells that are in some completion stage and I think at the end of this quarter, we are almost exactly 50. At the end of the second quarter, I think we are at 39 wells or 40 wells, so it went up a couple of wells, but it is in that same range.

Okay, so we shouldn't expect any major change in the number of wells, Fayetteville wells per quarter going forward. Should be in the order of 130-ish wells?

It goes back to that -- how fast you drill the wells but at the pace we're doing right now, between 130 wells and 135 wells, 136 wells is what we will drill a quarter and that will be about what we complete a quarter.

Okay, in the Smackover, you added 27,000 acres in the last quarter. Can you comment on what kind of acreage you're adding? Are you filling in the holes in the existing 400,000 acres? Or are you stepping out on the edges? And can you comment on what you think quality of the acreage is outside of the 487,000 acres that you own?

Well, we're -- the area that we are actually buying in has a lot more acreage than 487,000 acres in it. It is close to 800,000 acres -- it is actually a little over 800,000 acres that we think could be potential. Now, in that, there's some people already [own] some acreage and some of that gets subtracted back out.

The reason you are seeing the acreage go up a little bit and you'll see it over the next several quarters actually, is that when we announced the play last quarter, what we announced for the acreage we actually have is -- the acreage that we've found a land owner; we've made a deal with the landowner; we've checked title on it to make sure he actually owns it; and he's cashed a check.

There's some acreage, and really the acreage we have this quarter and the acreage we're going to have the next three quarters or four quarters that we found the landowner, we signed a contract with them. But we're out there doing the title work before we hand them then check and then they cash it to have it come in and be able to put it in the courthouse. So you are going to see it continue to go up, but it is not because necessarily we are pushing the boundaries of the play or anything; it is just nothing more than it takes time to get the title work done, especially on some of the smaller tracks that are out there. So, expect the acreage to go up, but some of that acreage is right in the heart of the play or most of it is in the heart of the play.

Got you. Okay. And then last question is, could you just -- you went through a nice summary of what you thought is going to happen to gas prices. Could you just give us an idea of the 900,000 acres in the Fayetteville, what proportion is economic at $3, $3.50, $4, $4.50 gas?

Let's start at the 900,000 acres. Now to remind everybody, the 900,000 acres is a little over 600,000 acres that we've drilled on. There's 100 -- about 60,000 acres that's federal acreage that we now have 6 wells on; they are all verticals and they're cored but there's no testing been done on those wells. And over the next several months, we will drill another 5 wells on that acreage. That's been a longer timeframe to test and do something with.

Then we have almost 150,000 acres that is in the older established part of the play that we've got held by production by a long time and we will get to it when we can get to it. When we usually talk about how many wells we have left to drill, we are only talking about what we've tested to date on 600,000 acres.

Now as you start thinking about the economics, when I said that we needed to have $4 flat going forward, that goes with the number that we always talked about, the 8,000 net wells that we have to drill or on a gross basis, because that net -- remember, we need you to remember we have 75% working interest. On a gross basis, that's almost 12,000 gross wells. That's where the $4 number comes in.

If you dropped down to $3.50, that 8,000 net drops down to the 2,000 net range at $3.50 so you do drop considerable off of that. I can't tell you what happens at $3, there's going to be some pieces that works at $3. But somewhere in the high $3, it starts dropping off pretty quick.

If you go to $4.50, do you add a lot more wells or is it still -- it tops out at around 8,000 acres for you?

Where you start seeing the real increase in wells is with the other acreage; it is not really with the pricing Because we pretty much got the spacing we need and almost all of our acreage at 600,000 acres is as economic as at 600,000 acres. There's a little bit of fringe stuff and I wouldn't even guess, it is 10% or 15% that even if we went to 5% that it would add to the well count. It would be mainly the North and some of the shallow areas right around the fringe of our acreage on the North Side.

Gil, remember that the well count that Steve was talking about is to hit our 1.3 PVI target.

Okay.

(multiple speakers) economic well.

You're talking about NYMEX price?

Yes.

Okay, thank you very much. Very helpful.

Michael Bodino of Global Hunter Securities.

Thank you. Good morning. Just a quick follow-up; most of my questions have been answered. With the Laser line now in service in Northeast Pennsylvania, can you give us a sense of what you expect to get completed in terms of a well count on the balance of the year in the Marcellus?

Yes, we were -- where the Laser line helps us is that it sends some gas to a little bit different pipelines so we get a little bit different price. It doesn't really help us towards the end of the year on any of our takeaway because we don't go into Laser; Right now we're going into Stagecoach.

And really, the only difference between what we're doing today and the end of the year will be Stagecoach has had some issues in September and October and actually, today has some compression issues. They did a major addition of compression in September right when the flooding was going on and we were completely down for about five days or six days. They've had some problems since then, but there's probably for us another 10 million to 15 million a day that we can get Stagecoach lines out there worked. We've got committed, we just haven't been able to put it into the line.

And then I mentioned we've got some permitting issues. There's a fifth compressor we need to put out on a certain site, we thought we'd have that permit by now; it looks like that will be late in the year. If it comes sooner than that, we've probably got another 15 million to 20 million a day that we can put on between now and the end of year, but that's the only thing between now and the end of the year.

And really, the numbers Greg mentioned earlier, we assume the compressor that bump up right at the very beginning of the year, that was a compressor coming on in January was our assumption there. That's where that comes from. So the next significant jump is when the DTU line comes in and we will work our way up to that, but the DTU line is sometime in the second quarter.

Thank you very much.

Robert Christensen of Buckingham Research.

Steve, on this lower Smackover first well, how's the trajectory of the lateral going right now? I think you wanted to stay fairly low. Is the drilling up to your expectations as we are in this lateral leg?

I'll give you two comments there. The actual formation we drilled it vertically and we did this coring; actual formation came within 10 feet of exactly where we had it mapped so it was dead on that direction. And that's one of the reasons we wanted to drill through it besides the core was we wanted the land in the bottom basically 40 feet or 50 feet of the Brown Dense. We're in that. I don't know exactly how many feet we're out right now, we're out a couple thousand feet at this point, not quite 2000 feet at this point. And so far, we're right in zone and haven't had any issues.

Can you speak to Exxon's interest in the play? And I think one time you had mentioned that they had proposed a joint 3D seismic survey of their lands and yours. Any thoughts on what the giant might be doing?

I really don't have any thoughts. We are still talking about 3Ds or shooting some seismic together but we really haven't gotten indication, I think, drilling that they may do. And for everyone, Exxon has a position basically East to where we are drilling, almost on the Louisiana-Arkansas border.

Could you characterize what the 1 or 2 principal risks are in this exploratory well?

I think there's 2 risks -- the one is well -- the one core we have in the area shows good porosity, permeability, all the things that you'd hope to see in a core. You just don't know outside of that one core what the real characteristics of all the rock is. You've done all the calculations but then you need to get some core, and then you get some other wells with a lot of data; and very well could be that there is parts of this play that don't have those characteristics, and are too tight or have some issue, you can't frac them. And so the play is smaller than you think it is. That would be one issue.

I think the other issue is you've got the Brown Dense, the Brown Dense that we are going for is 300-foot to 500-foot thick. Right above the Brown Dense is the middle Smackover; the middle Smackover is about 150-foot thick. It is a very, very tight -- bright white limestone and we are considering it the seal for the Brown Dense. Then above that tight limestone is the conventional Smackover that all these fields in southern Arkansas and northern Louisiana produce oil from for all those years. That upper Smackover has very high porosity permeability and has water.

So somehow, either it's from a fault that would go from the upper Smackover oil all the way down into the Brown Dense or from -- it would be really strange to have a frac go that high but if -- somehow if you could frac through all the Brown Dense through to 200 feet of tight rock and then get into that, you could actually have water come from that upper interval. So those are the two risks in the play.

Thank you very much.

(Operator Instructions)

Hsulin Peng of Robert W. Baird.

Good morning, gentlemen. A quick follow-up question, the $5.5 million Marcellus well cost, is that with pad drilling?

And second question is, are you -- can you talk about the service cost trends that you are seeing in Marcellus and also the availability?

Okay, your first question had to do with whether that was all-in cost?

Right, also with the pad drilling, if you anticipating any additional savings from that?

All of our wells to date have had basically pad drilling. I think the fewest number of wells we put on our pad is 3. And as I said, we're about ready to do a 5 well pad. So there's some, if you want call it cost savings, efficiency something from drilling 2 or 3 to a pad. Ultimately, I think you're going to have less wells per pad in Pennsylvania than you do in Fayetteville Shale.

The reason I say that, it looks like it is going to be wider spacing. Where we talk about 40- and 60-acre spacing in Fayetteville Shale, it looks like it is going to be over 100-acre spacing here. So you won't have as much chance as a pad efficiency just because you are going to have more pads and fewer wells per pad. But that's still all to be learned on that side of it.

Now as far as costs go, I've got to frame this a little bit. In the case of the Marcellus, to drill an identical well in the Fayetteville Shale to that $5.5 million well in the Marcellus would probably be the high $3 million -- $3.6 million, $3.7 million. So there's significant cost differences between Fayetteville and Marcellus. Some of those are terrain, some of those are permitting, some of those are water, handling that your -- they are just different or you're not going to get around them. The other part of those are just your -- the fact that the rig count has gone up so quickly in Pennsylvania and the surfaces have been difficult to find historically.

You're starting to see the surfaces because the rig count stayed flat for the last six months or seven months. The surfaces are starting to be more available to you.

I think I've said this in the past, this time last year, if you could find frac equipment, you took whatever you had and didn't matter how good the equipment was, how bad the equipment was, you just took and went with it. Today, you can actually call and 30 days down the road, talk to several vendors and get frac equipment out there. The cost are still about 20% higher than Fayetteville Shale but there are flat, really from -- have gone down a little bit from the beginning of the year. But they have been flat the last couple of quarters.

Okay, thank you.

Rehan Rashid with FBR Capital Markets.

On the new business ventures group, the other 0.5 million acres, what will it take to have some more open discussion with us in terms of where it is located and what the plan would be? What are we waiting for, Steve?

It's just like it was before we announced the Brown Dense play. We need to get all the acreage we've targeted for any one of those areas. And once we get the acreage put together in any of those areas and we've control -- we would think we need to control, then we will start talking about it. And I would expect that next year, we will talk about at least one more area at the pace we're going right now in some of the ones we are doing.

And again, that acreage isn't just one area; there's more than one area we are putting acreage together on. I would expect that next year third quarter conference call we've got some acreage and you're ask the same questions about when we are going to know about it as well.

Okay, okay. Back to the Fayetteville real quick. As I look at the decline curve for greater than 4000-foot laterals, greater than 5000-foot laterals, towards the back end of the decline curve, I see it bounce back up in productivity rates a couple of hundred days down the road. Can you tell us why? Is that a data aberration or associated gas coming out, any thoughts on that front?

No, I don't think -- it is a good question. I think it is more data aberration and one of the things we do in our curves is we try and show you how many wells that go into that portion of the curve and we do it by color code. In that top blue curve when it starts bumping up especially, I'd say we're 400 days on -- you can see that there's only about 36 wells and it drops quickly down to 1 well versus the beginning of that curve has over 250 wells in it. So I think you're just seeing an aberration of those various wells just having only 30 versus 250.

Now, I think the other part of what you were asking though is we do have a significant amount of, what we call absorbed gas. And adsorbed gas comes out with a pressure drop and the flattening you see in all those curves, doesn't matter which lateral length, is showing you that adsorbed gas. In our case, about 40% of our gas that we have is what we call free gas; it's in the fractures that's what gives you the IP, that's what gives you the beginning first year, 1.5 year production. And we're probably in some of these now, we've got enough days on them, on those other curves that, that flattening is you're actually starting to see some absorbed gas coming in the system.

Okay, thank you.

Michael McAllister with Sterne, Agee.

Good morning guys. My question is from your comments, I guess, earlier in the Q&A about the type of Marcellus wells that you want to drill with longer laterals and greater frac stages. Should we be using a -- something higher or something closer to $7 million per well as a cost going forward rather than the $5.5 million which is the 10 stage frac number?

I don't know the answer to that. If -- just to -- and really I'm just guessing here, and I'm guessing as much from our experience as well as just hearing anecdotally from some of the operators around us. My guess is we're not going to end up with a 10 stage, 11 stage average that it will probably be 14 stage, 15 stage. 14 stage to 15 stage well would be $6.5 million to $7 million.

So I'm thinking it is going that direction. But we are still doing a lot of testing to make sure that really is right or not.

So you're still going to be like in the mix for at least 2012?

Yes, for a while. (multiple speakers) The other thing that everyone needs to keep in mind, in Pennsylvania, part of your lateral length is how you can put your units together. And most of the units that we have are in the 500-acre to 700-acre size units which would be between 4000-foot and maybe as high as 6000-foot laterals. We do have some that are bigger, so -- but that also does a little bit of limitation on lateral length which also then factors back in the number of stages also.

Okay, great. And will Southwestern be leveraging William Way's international experience?

We certainly had talked to various international operators that they've -- we get calls all the time, somebody wants to learn about what we are doing and how we are doing. And if the right deal came along, you might see us do something with someone. But it is not the primary driver of what we are doing. Our primary driver is working North America and pick up this acreage that we're working on, going in that direction. So another way to answer that, of that new ventures acreage that's the -- we are not talking much about, none of that at this point is in Canada and none of it is international someplace else.

Okay, fair enough. Thank you.

Thank you. Mario Barraza, Tuohy Brothers.

Hi guys. All my questions have been answered, thank you.

Thank you. There are no further questions at this time. I would now like to turn the floor over to Mr. Mueller for closing comments.

Thank you. I started today saying we are very excited -- and we are very excited for a lot of different reasons. We continue to make very good money in today's price environment. And as I talked about, we think it is going to be around for awhile and we believe we are one of the few operators that can really do that.

We are excited about the Fayetteville Shale. And in the case the Fayetteville Shale, we're doing that drilling, the days are coming down and we're getting more efficient. There is more efficiencies to take out. So we are comfortable that, over the next few years, we can drill wells at the same cost we are doing today and continue to do what we are doing on the production and EUR side of that.

I'm excited about Pennsylvania and we've shown in the graphs and our presentation we sent out and those wells are looking really good. We do have the firm that we need to ramp up our production. We're getting the rigs and so we are starting to get that going in our direction as well.

Then when you look at the new ventures, we're drilling that first well in the Brown Dense and we are continuing to get more information in New Brunswick. Things are working for us. We are looking forward to a really good fourth quarter and a real exciting 2012.

And with that, I thank you for listening to our call today and I wish you the best over the next quarter. Thank you.

This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.